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In the 2023 phase of the international collaborative DECOVALEX modeling project, Task E focused on understanding thermal, hydrological, and mechanical (THM) processes related to predicting brine migration in the excavation damaged zone around a heated excavation in salt. Salt is attractive as a disposal medium for radioactive waste because it is self-healing and is essentially impermeable and non-porous in the far field. Investigation of the short-term, near-field behavior is important for radioactive waste disposal because this early period strongly controls the amount of inflowing brine. Brine leads to corrosion of waste forms and waste packages, and possible dissolution of radionuclides with brine transport being a potential transport vector to the accessible environment.The Task was divided into steps. Step 0 included matching unheated brine inflow data from boreholes at the Waste Isolation Pilot Plant (WIPP) and matching temperature observations during a Brine Availability Test in Salt (BATS) heater test. Step 1 included validation of models against a thermo-poroelastic analytical solution, and two-phase flow around an excavation. Finally, Step 2 required all the individual components covered in steps 0 and 1 to come together to match observed brine inflow behavior during the same BATS heater test.There were a range of approaches from the teams, from mechanistic to prescriptive. Given the uncertainties in the problem, some teams used one- or two-dimensional models of the processes, while other teams included more geometrical complexity in three-dimensional models. Task E was a learning experience for the teams involved, and feedback from the modeling teams has led to changes in follow-on BATS experiments at WIPP. The primary Task E lessons learned were the impact of hydrologic initialization methods (wetting up vs. drying down), the difference between confined and unconfined thermal expansion, and the large changes in permeability associated with heating and cooling.

To ensure the safety of geological disposal of high-level radioactive waste, in-situ experiments have been carried out to examine the behavior of rocks in underground research laboratories (URLs). At the Meuse/Haute-Marne URL in France, the French National Radioactive Waste Management Agency (Andra) has been assessing the Callovo-Oxfordian claystone (COx) as potential host rock of geological disposal by subjecting the COx to in-situ heating mimicking exothermic radioactive waste. Results of the in-situ experiments are used to validate and bolster the numerical simulators for predicting the thermo-hydromechanically (THM) coupled behavior of the COx. The numerical simulators are, however, yet to be tested for predicting the failure and fracture development of the COx during heating, which is of paramount importance to the safety of the geological disposal. In this research, we modelled a recently carried out in-situ experiment at the Meuse/Haute-Marne URL using the TOUGH-FLAC simulator to predict the failure and fracture development of the COx during heating. The objectives are to examine the effects of (i) the weak bedding planes, (ii) the softening rate of matrix/weak plane strengths, and (iii) the stiffness anisotropy of the COx on the development of shear and tensile fractures during heating. Results show that considering failure along the weak planes enabled accurate predictions of fracture development. Also, fracture development intensified at a softening rate beyond a threshold level and the geometry of fractures was significantly affected by the stiffness anisotropy. These results will help boost the reliability of the safety and performance assessment of geological disposal in claystone.

We conducted two-dimensional numerical simulations to investigate the mechanisms underlying the strong spatiotemporal correlation observed between submarine landslides and gas hydrate dissociation due to glacial sea-level drops. Our results suggest that potential plastic deformation or slip could occur at localized and small scales in the shallow-water portion of the gas hydrate stability zone (GHSZ). This shallow-water portion of the GHSZ typically lies within the area enclosed by three points: the BGHSZ–seafloor intersection, the seafloor at ∼600 m below sea level (mbsl), and the base of the GHSZ (BGHSZ) at ∼1,050 mbsl in low-latitude regions. The deep BGHSZ (>1,050 mbsl) could not slip; therefore, the entire BGHSZ was not a complete slip surface. Glacial hydrate dissociation alone is unlikely to cause large-scale submarine landslides. Observed deep-water (much greater than 600 mbsl) turbidites containing geochemical evidence of glacial hydrate dissociation potentially formed from erosion or detachment in the GHSZ pinch-out zone.

Salt formations are a promising host rock for the disposal of heat-emitting nuclear waste due to their ability to heal fractures, high thermal conductivity, and near-zero permeability. This study investigates the concept of waste emplacement in salt formations by placing waste packages in drifts and backfilling them with crushed salt. The aim is to minimize fracturing and restore the initial properties of the host rock. One of the key issues in assessing the safety and performance of nuclear waste repositories in salt is determining the reconsolidation rate of the crushed salt backfill, which has been traditionally predicted using the C-WIPP model. However, this model was calibrated using data from uniaxial oedometer lab tests, where specimens with high initial porosity values have been compacted to medium porosity values. The observed compaction behavior has then been extrapolated to the low porosity range, leading to a prediction of rapid full reconsolidation of the backfill in less than 20 years. In contrast, the new C-WIPP/TUC model used in this study was calibrated for the medium porosity range, between 17% and 8%, based on more suitable triaxial lab tests. Using coupled Thermo-Hydro-Mechanical (THM) simulations with the TOUGH-FLAC simulator, it was found that the C-WIPP/TUC model predicts a slower reconsolidation rate of the backfill compared to the C-WIPP model, with an average porosity of the backfill remaining roughly 10 times that of natural salt after 10,000 years. The effects of the relatively slow reconsolidation of the crushed salt backfill on the THM behavior of the repository are also examined, highlighting the importance of accurately capturing the behavior of crushed salt for the study of the long-term integrity of a nuclear waste repository in salt.

Geologic storage of carbon dioxide can efficiently contribute to reduce greenhouse gas emissions to the atmosphere. Two major hazards of this technology are leakage towards the ground surface and fluid-induced seismicity. While major faults may be detected and avoided during site characterization, undetected subseismic faults could be encountered once injection has started. This paper investigates leakage and reactivation of undetected faults through coupled thermal–hydraulic–mechanical modeling. The simulations are performed using a recently developed sequential simulator, TOUGH-Pylith, that allows to accurately account for the thermodynamics of brine-CO2 mixtures, and to model faults as surfaces of discontinuity using state-of-the-art fault friction laws. The simulator is benchmarked against well-known analytical solutions and subsequently applied to investigate two cases of CO2 injection close to undetected faults under normal and strike-slip faulting regimes. Although the scenarios are generic and represent unfavorable conditions, they suggest that leakage could occur and that undetected faults could trigger minor seismic events. Therefore, careful site characterization and continuous monitoring during operations should be always performed.

Injection of CO2 for geologic carbon sequestration into deep sedimentary formations involves fluid pressure increases that engage hydromechanical processes that can cause seismicity by activation of existing faults. In this work, we use a coupled multiphase fluid flow and geomechanical simulator to model spatiotemporal fluid pressure and stress changes in order to study the poroelastic effect of CO2 injection on faults in crystalline basement rock below the injection zone. The seismicity rate along features interpreted to be basement faults is modeled using Dieterich's rate-and-state earthquake nucleation model. The methodology is applied to microseismicity detected during CO2 injection into the Mount Simon formation during the Illinois Basin—Decatur Project. The modeling accurately captures an observed reduction in seismicity rate when the injection in the second well was into a slightly shallower zone above the base of the Mount Simon formation. Moreover, the modeling shows that it is important to consider poroelastic stress changes, in addition to fluid pressure changes for accurately modeling of the observed seismicity rate.

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.

In the study, we analyze changes in groundwater pressure observed in several boreholes drilled in and around the Mizunami Underground Research Laboratory (MIU) induced by the 2011 off the Pacific coast of Tohoku Earthquake (Mw 9.0). The aim of this project is a development of methodology to evaluate systematic fault activity by numerical analysis. To reach this goal we investigate the behavior of the fault zones present in the area during the passing of seismic waves. We built a simplified hydrogeological model of the MIU site and performed a series of fluid flow simulations with TOUGH2 flow numerical code. We investigate how changes in permeability along three faults present in the study area: the Tsukiyoshi Fault, the Hiyoshi Fault and the Main-Shaft Fault may have influence the groundwater level monitored in boreholes intervals. We also test the influence of the cone of depression at the MIU site and the hydraulic connectivity between the sedimentary cover and the granite aquifers. Our results suggest that two main mechanisms are responsible for the observed changes in groundwater pressure: (1) crustal dilation induced by the Tohoku earthquake causing a groundwater recharge from the sedimentary aquifers to the Toki granite aquifer where the sedimentary cover is thick; and (2) permeability increase along faults critically oriented for shear reactivation and oriented in the direction of the passing seismic wave. In this case, the seismic wave increases the shear stress acting on the fault promoting slip and a change in permeability through a mechanism of slip-induced dilation. Faults not critically stressed and faults critically oriented for shear reactivation but oriented perpendicular to the passing seismic wave are not reactivated.

Microscale numerical modeling is potentially an effective approach for understanding salt creep, but it is quite challenging because natural salt grain boundaries can have complex and evolving geometry, and because contacts between these deformable salt mineral grains are dynamic as a result of compaction, chemical reaction, fluid flow, and heat transfer. In this study, we have overcome these challenges and developed a new microscale mechanical-chemical (MC) model to analyze creep of salt at the microscale, accounting for coupled deformation, dynamic contacts, and chemical reaction in granular systems with realistic geometric representations. The MC model was realized by linking a new microscale mechanical code based on the numerical manifold method (NMM) to a reactive transport code named Crunch. We simulated the processes of reorganization of the salt grains, microfracturing, and pressure solution that contribute to creep at larger scales. Based on this first quantitative microscale model, we found that sharp corners of mineral grains can dominate the contact dynamics, microfracturing, and pressure solution when salt is compacted, thus governing the structural changes and porosity loss of the system. We found that pressure solution, which preferentially dissolves sharp corners and edges, can lead to relatively high porosity loss in the system, thus playing an important role in the creep of salt. Our analysis shows that the dynamic changes of salt granular systems involving grain relocation and pressure solution can occur repeatedly and continuously, thus contributing to longer-term creep of salt at larger scales.

Observations on tens-of-meter scale experiments of fault activation by fluid injection conducted in shales allow exploring how aseismic and seismic events may jeopardize the integrity of a sealing caprock overlying a CO2 sequestration reservoir. We contrast the behavior of shale faults with another set of experiments conducted in carbonates. Significant fluid leakage occurs along the initially low-permeability shale faults when rupture is activated. Most of the leakage pathway closes when fluid injection ceases and fluid pressure drops. Dilatant slip on the fault plane alone does not explain the observed leakage behavior, which is also caused by fault opening favored by the softness of the shale, and by the structure of the fault zone that prevents fluids from diffusing into the adjacent damage zone. Experiments show a large amount of aseismic deformation. Small-magnitude seismicity (Mw < -2.5) is observed outside the pressurized leakage patch. Stress transferred from this aseismic deformation patch can build up to stress-criticality and favor seismicity. Thus, in terms of fault activation in caprocks, aseismic fault slip leading to increased permeability and a loss of seal integrity is of great concern.

This study presents comprehensive coupled hydro-mechanical numerical modeling of the first and second hydraulic stimulations at the Pohang enhanced geothermal system (EGS) site in order to improve the understanding on the key stimulation mechanisms in the fractured reservoir. Two models for PX-2 and PX-1 wells were developed including fracture zones of different orientations and permeability. Shear dilation and frictional plastic strain-softening were implemented in a non-linear stress dependent fracture model. A history matching of the wellhead pressure curves was carried out in the early days of each stimulation. The PX-2 model with a fracture jacking mechanism achieved the reproduction of highly reversible non-linear aperture changes observed in situ. The PX-1 model successfully simulated a wellhead pressure peak and drop associated with shear slip and dilation by applying frictional plastic strain softening. Simulated critical wellhead pressure for shear slip near the PX-1 well was greater than the prediction by a simple slip potential analysis due to local stress changes by the poroelastic effect. The numerical modeling confirmed that the combination of shear dilation and jacking was adequate to capture the pressure evolution during the increasing step-rate test at PX-1. Besides, spatio-temporal changes in pressure, total stress, and permeability evaluated in the fracture zones greatly enhanced the understanding on the coupled behavior caused by the hydraulic stimulations. The possibility of zones with lower permeability away from the PX-1 well was suggested by an alternative model. The current numerical study demonstrates that the key hydro-mechanical processes of shear slip and dilation and hydraulic jacking observed in the fractured reservoir can be successfully reproduced.

Establishing the geomechanical stability of marine sediments in the vicinity of a production well is one of the key design considerations in planning offshore gas production from marine hydrate reservoirs. This paper presents an assessment of the sediment stability at India's National Gas Hydrate Program, Expedition 2 (NGHP-02) Site 16 Area B offshore eastern India, for which gas production is to be carried out by depressurization. One important feature of the study is that extensive calibration of constitutive model parameters has been conducted based on laboratory test data from pressured core samples. From analysis perspective, the site is challenging because the hydrate reservoir consists of thin layers of hydrate-bearing sands interbedded with mud. Moreover, depressurization at the depth of a reservoir more than 2750 m below sea surface will lead to a pore pressure drop, and accordingly an effective confining stress increase as high as 25 MPa. In dealing with thin interbedded hydrate-bearing strata, meshing requirements for flow and geomechanical analysis are quite different from those for reservoirs with thicker massive layers, An axisymmetric model and one-way coupling simulations were thus adopted for this study, in which the geomechanical study utilizes pore pressure and hydrate saturation output from the flow study, but the flow study does not takes the porosity changes from the geomechanical analysis. Instead, the reduction of porosity due to sediment deformation in the flow study is based on a pressure-dependent pore compressibility relationship derived from geomechanical modeling. The rationality is validated through back computing the pore compressibility from the geomechanical deformation results. The study shows that large compression in the reservoir will result in movement of the sediments from above and below, as well as laterally in smaller magnitudes; and the sediment is deemed stable during the gas production period.

Free gas migration through the gas hydrate stability zone (GHSZ) and subsequent gas seepage at the seabed are characteristic features in marine gas hydrate provinces worldwide. The biogenic or thermogenic gas is typically transported along faults from deeper sediment strata to the GHSZ. Several mechanisms have been proposed to explain free gas transport through the GHSZ. While inhibition of hydrate formation by elevated salinities and temperatures have been addressed previously in studies simulating unfocused, area-wide upward advection of gas, which is not adequately supported by field observations, the role of focused gas flow through chimney-like structures has been underappreciated in this context. Our simulations suggest that gas migration through the GHSZ is, fundamentally, a result of methane gas supply in excess of its consumption by hydrate formation. The required high gas flux is driven by local overpressure, built up from gas accumulating below the base of the GHSZ that fractures the overburden when exceeding a critical pressure, thereby creating the chimney-like migration pathway. Initially rapid hydrate formation raises the temperature in the chimney structure, thereby facilitating further gas transport through the GHSZ. As a consequence, high hydrate saturations form preferentially close to the seafloor, where temperatures drop to bottom water values, producing a prominent subsurface salinity peak. Over time, hydrates form at a lower rate throughout the chimney structure, while initial temperature elevation and salinity peak dissipate. Thus, our simulations suggest that the near-surface salinity peak and elevated temperatures are a result of transient high-flux gas migration through the GHSZ.

Numerous analytical solutions have been developed for modeling thermal perturbations to underground formations caused by deep-well injection of fluids. Each solution has been derived for a specific boundary value problem and a simplified flow network with one set of parallel fractures. In this paper, new generalized solutions G*(x, s) are developed using (existing) global transfer functionsG*0 (x,s) and a new memory function g*(s), where x and s are the space and Laplace variable. The memory function represents the solutions of conductive heat exchange between fractures and matrix blocks and between fractured aquifers and unfractured aquitards. The memory function is developed to account for multirate exchange induced by different shapes, sizes, properties, and volumetric fractions of matrix blocks bounded by multiple sets of orthogonal fractures with different spacing. The global transfer functions represent the fundamental solutions to convective, convective-conductive, and convective-dispersive heat transport in fractures (or aquifers) without exchange and are available for various (1-D linear, 1-D radial, 2-D dipole, and single-well injection-withdrawal) flow fields. The new solutionswith exchange are developed usingG*(x,s) = B*(s)G*0{x, s[1 + Θg*(s)]}, thereby greatly simplifying solution development in a novel way, where Θ and B*(s) are a fracture-matrix scaling factor and the boundary condition function. The new solutions are applied to several example problems, showing that heat transport in fractured aquifers is significantly impacted by (1) thermal dispersion in fractures that is rarely considered, (2) multirate heat exchange with a wide range of size and anisotropy of rectangular matrix blocks, and (3) heat exchange between aquifers and aquitards.

The center of the San Joaquin Valley is one of the most productive agricultural regions in the US. Farmers rely heavily on surface-water diversions to meet irrigation water demand. However, the 2007–2010 and 2012–2017 droughts have caused strong increases in groundwater pumping causing land subsidence with strong variability in location, magnitude (total subsidence) and rate of subsidence. In this study, we try to understand what caused these variations. We focus our analyses on three areas: (i) the Westland water district where subsidence was very small during the two drought periods, (ii) ‘El Nido’ area where the greatest subsidence rate was monitored from 2008 to 2010, and (iii) the’ Kings-Tulare counties’ area where the subsidence was small during the 2008–2010 and the largest during 2015–2017 droughts. Our main finding is that land subsidence is located in areas where the water demand for agriculture and the density of groundwater wells is the highest, whereas the rate of subsidence is strongly affected the amount of local and imported surface water and by groundwater resources. Based on these simple observations, we propose using continuous satellite-based ground deformation monitoring and geomechanical modeling to (i) localize areas most prone for future subsidence and (ii) to estimate and manage groundwater resources.

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.

Faults in the host rock that might exist in the vicinity of deep geological repositories for radioactive waste, constitute potential enhanced pathways for radionuclide migration. Several processes might trigger pore pressure increases in the faults leading to fault failure and induced seismicity, and increase the faults’ permeability. In this research, we developed a mathematical model to simulate fault activation during an experiment of controlled water injection in a fault at the Mont-Terri Underground Research Laboratory in Switzerland. The effects of in-situ stress, fault shear strength parameters and heterogeneity are assessed. It was shown that the above factors are critical and need to be adequately characterized in order to predict the faults’ hydro-mechanical behaviour.

In this study, we analyze a deep hydraulic stimulation of a fracture zone that was conducted as part of the classical Fenton Hill Hot Dry Rock Program in the 1970s. At the time, it was suggested that a pre-existing fracture or multiple fractures within the fracture zone were jacked open by injection-induced increase in pressure. In this study, we analyze the same stimulation experiment, but investigate the possibility of an alternative mechanism of shear reactivation of pre-existing fractures. We conduct modeling that accounts for both jacking (or elastic-fracture opening) and shear-slip dilation and demonstrate that injection-induced shear reactivation (or hydroshearing) could have occurred simultaneously with seismic events of magnitudes lower than what can be felt by humans. In fact, simulations considering shear reactivation seem to better match observed fluid recovery after multiple injection cycles. Shear reactivation and shear dilation results in locked-open fractures, especially near the injection well that provides permeability of higher flow recovery. We then investigate the sensitivity of the proposed model by varying some of the critical parameters such as maximum aperture, dilation angle, as well as fracture density. Interestingly, none of the simulated cases resulted in a large event that could have been felt by humans, but did result in a cumulative seismic magnitude of less than 1 for each given stimulation step. These results suggest that a permanent irreversible permeability increase of several orders of magnitude can be obtained by hydroshearing in a “seismically” safe manner.

In the paper already published, there is an error in the acknowledgements. The grant number concerning EU project is 636811 instead of 640979. There was a misunderstanding with the EU project number and we only found that after those papers are published. We confirm that the correction is to be made online and we also want to publish a corrigendum. The corrected text should be: The authors regret . “The authors gratefully acknowledge the Swedish Geological Survey (SGU), grant number 1724, and the EU project Fracrisk grant number 636811, for providing financial support to research reported in this paper. Additional support was provided by the U.S. Department of Energy under contract No. DE-AC02-05CH11231.” The authors would like to apologise for any inconvenience caused.

The authors regret the error regarding the grant number in the acknowledgements in the paper already published. The grant number concerning EU project is 636811 instead of 640979. There was a misunderstanding with the EU project number and we only found that after those papers are published. The corrected text should be: “The authors gratefully acknowledge the Swedish Geological Survey (SGU), grant number 1724, and the EU project Fracrisk grant number 636811, for providing financial support to research reported in this paper. Additional support was provided by the U.S. Department of Energy under contract No. DE-AC02-05CH11231.” The authors would like to apologise for any inconvenience caused.

We studied the relation between rupture and changes in permeability within a fault zone intersecting the Opalinus Clay formation at 300 m depth in the Mont Terri Underground Research Laboratory (Switzerland). A series of water injection experiments were performed in a borehole straddle interval set within the damage zone of the main fault. A three-component displacement sensor allowed an estimation of the displacement of a minor fault plane reactivated during a succession of step rate pressure tests. The experiment reveals that the fault hydromechanical (HM) behavior is different from one test to the other with varying pressure levels needed to trigger rupture and different slip behavior under similar pressure conditions. Numerical simulations were performed to better understand the reason for such different behavior and to investigate the relation between rupture nucleation, permeability change, pressure diffusion, and rupture propagation. Our main findings are as follows: (i) a rate frictional law and a rate-and-state permeability law can reproduce the first test, but it appears that the rate constitutive parameters must be pressure dependent to reproduce the complex HM behavior observed during the successive injection tests; (ii) almost similar ruptures can create or destroy the fluid diffusion pathways; (iii) a too high or too low diffusivity created by the main rupture prevents secondary rupture events from occurring whereas “intermediate” diffusivity favors the nucleation of a secondary rupture associated with the fluid diffusion. However, because rupture may in certain cases destroy permeability, this succession of ruptures may not necessarily create a continuous hydraulic pathway.

Subsurface manipulations such as those expected from the disposal of heat-emanating radioactive waste in deep repositories can induce strongly coupled Thermal (T), hydrological (H), mechanical (M) and chemical (C) processes. Adequate coupled THMC models are highly desirable or even indispensable for performance assessment of such repositories, for examples for the analysis of bentonite-based engineered barrier system (EBS) surrounding the emplaced waste. In this study, we present coupled THMC model simulations of a generic nuclear waste repository in an argillite with a bentonite-based buffer. The objective is to evaluate the chemical changes in the EBS bentonite and their effect on mechanical behavior under high temperature, attempting to shed light on whether EBS bentonite can sustain temperatures higher than 100 °C without significant impact on barrier's performance. Two scenarios were simulated for comparison: a case in which the temperature near the waste canister peaks at 200 °C and a case in which the temperature at the same spot culminate with about 100 °C. Simulations for a generic case with Kunigel-VI bentonite as backfill and Opalinus Clay as host rock were conducted for 1000 years and reported in the previous study (Zheng et al., 2015). In this paper, simulations for 100,000 years have been done for two types of bentonite-based buffer materials: Kunigel-VI and FEBEX bentonite. This enables us to evaluate how different types of bentonite behave in terms of the illitization and its impact on swelling stress and whether we can generalize these results to support decision making. The simulations show the occurrence of illitization in the bentonite buffer and the enhancement of illitization under high temperature. However, FEBEX bentonite undergoes less illitization mainly due to the higher ion concentration in pore water and the lower content of K-feldspar in the bentonite mineral composition. Moreover, the reduction of swelling stress by chemical changes is more pronounced for Kunigel-VI bentonite than for FEBEX bentonite. Overall, the results of our model simulations suggest that an argillite repository with a bentonite-based EBS that is similar to FEBEX bentonite could sustain temperatures much higher than 100 °C as far as illitization concerns. Model results also reveal that illitization is stabilized after about 2000 years in bentonite near the waste package, but continues in bentonite near the bentonite-argillite interface, which manifests the strong effect of geochemical interaction between EBS bentonite and host rock on long term illitization in bentonite.

Cold water injection into a hot, fractured, geothermal reservoir may trigger shear activation of pre-existing fractures that can help to enhance reservoir permeability, but may also result in unwanted seismicity. In this paper, we investigate through numerical modeling of a hypothetical geothermal reservoir how injection-induced cooling may influence the potential for shear activation, paying special attention to the evolution of deviatoric stress under various stress regimes. In each case, we consider either a reservoir with homogeneous hydraulic properties or the presence of a more permeable fracture zone intersecting the injection well. This fracture zone is either oriented in the maximum (SHmax) or minimum (Shmin) horizontal stress direction. Our main finding is that depending on the configuration, injection-induced cooling stresses can favor or prevent shear reactivation of the preexisting fracture, and this effect can vary temporally and spatially.

Fracture propagation caused by hydraulic fracturing operations can be significantly influenced by adjacent fractures. This paper presents a detailed coupled hydro-mechanical analysis to study the effects of nearby natural fractures on hydraulically induced fracture propagation and changes in fracture permeability. Two rock domains were considered in comparison: FD1, with one fracture, and FD2, with two adjacent parallel or non-parallel fractures. It was assumed that water injection occurred in a borehole that intersected the single fracture in FD1 and one of the two fractures in FD2. Simulations were made for a time period of 3 h with an injection period of 2 h followed by 1 h of shut-in. An elastic-brittle model based on the degradation of material properties was implemented in a 2D finite-difference scheme and used for elements of the intact rock subjected to tension and shear failure. The intact rock was considered to have a low but non-negligible permeability. A verification study against analytical solutions showed that the fracture propagation and stress concentrations due to differential boundary stresses could be accurately represented by our model. Next, a base case was considered, in which the stress ratio (SR) between the magnitudes of the maximum and minimum boundary stresses, the permeability kR of the intact rock and the initial permeability kTF of the tension failure regions were fixed. In FD2, the distance dF between the two natural fractures defined by the closest distance was also fixed. The results showed that in both rock domains, the fracture started to propagate when the pore pressure was approximately 85% of the magnitude of the minimum boundary stress. The propagation of a single fracture was significantly greater than the propagation of a double fracture system because, in the latter case, the pore pressure decreased when the two fractures connected. As a result, changes in permeability in FD2 were smaller than in FD1. At the end of injection, the maximum ratios between the final and initial permeability of the natural fractures were found to be approximately 3 and 2 for rock domains FD1 and FD2, respectively. For non-parallel fractures, the controlling factor for fracture propagation was the separation between the tips of the pressurised fracture and the neighbouring non-pressurised fracture. A sensitivity study was conducted to study the influence of the key parameters dF, SR, kR and kTF on the simulation results. Fracture propagation showed more sensitivity to dF and SR than to the other parameters.

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.

We studied the elastic properties of a fault zone intersecting the Opalinus Clay formation at 300 m depth in the Mont Terri Underground Research Laboratory (Switzerland). Four controlled water injection experiments were performed in borehole straddle intervals set at successive locations across the fault zone. A three-component displacement sensor, which allowed capturing the borehole wall movements during injection, was used to estimate the elastic properties of representative locations across the fault zone, from the host rock to the damage zone to the fault core. Young's moduli were estimated by both an analytical approach and numerical finite difference modeling. Results show a decrease in Young's modulus from the host rock to the damage zone by a factor of 5 and from the damage zone to the fault core by a factor of 2. In the host rock, our results are in reasonable agreement with laboratory data showing a strong elastic anisotropy characterized by the direction of the plane of isotropy parallel to the laminar structure of the shale formation. In the fault zone, strong rotations of the direction of anisotropy can be observed. The plane of isotropy can be oriented either parallel to bedding (when few discontinuities are present), parallel to the direction of the main fracture family intersecting the zone, and possibly oriented parallel or perpendicular to the fractures critically oriented for shear reactivation (when repeated past rupture along this plane has created a zone).

CO2-enhanced coalbed methane recovery, also known as CO2-ECBM, is a potential win-win approach for enhanced methane production while simultaneously sequestering injected anthropogenic CO2 to decrease CO2 emissions into the atmosphere. In this paper, CO2-ECBM is simulated using a coupled thermal–hydrological–mechanical (THM) numerical model that considers multiphase (gas and water) flow and solubility, multicomponent (CO2 and CH4) diffusion and adsorption, heat transfer and coal deformation. The coupled model is based on the TOUGH-FLAC simulator, which is applied here for the first time to model CO2-ECBM. The capacity of the simulator for modeling methane production is verified by a code-to-code comparison with the general-purpose finite-element solver COMSOL. Then, the TOUGH-FLAC simulator is applied in an isothermal simulation to study the variations in permeability evolution during a CO2-ECBM operation while considering four different stress-dependent permeability models that have been implemented into the simulator. Finally, the TOUGH-FLAC simulator is applied in non-isothermal simulations to model THM responses during a CO2-ECBM operation. The simulations show that the permeability evolution, mechanical stress, and deformation are all affected by changes in pressure, temperature and adsorption swelling, with adsorption swelling having the largest effect. The calculated stress changes do not induce any mechanical failure in the coal seam, except near the injection well in one case of a very unfavorable stress field.

Hydraulic fracturing has been applied to extract gas from shale-gas reservoirs. Complicated geological settings, such as spatial variability of the rock mass properties, local heterogeneities, complex in situ stress field, and pre-existing bedding planes and faults, could make hydraulic fracturing a challenging task. In order to effectively and economically recover gas from such reservoirs, it is crucial to explore how hydraulic fracturing performs in such complex geological settings. For this purpose, numerical modelling plays an important role because such conditions cannot be reproduced by laboratory experiments. This paper focuses on the analysis of the influence of confining formations and pre-existing bedding planes and faults on the hydraulically-induced propagation of a vertical fracture, which will be called injection fracture, in a shale-gas reservoir. An elastic-brittle model based on material property degradation was implemented in a 2D finite-difference scheme and used for rock elements subjected to tension and shear failure. A base case is considered, in which the ratio SR between the magnitudes of the horizontal and vertical stresses, the permeability kc of the confining formations, the elastic modulus Ep and initial permeability kp of the bedding plane and the initial fault permeability kF are fixed at reasonable values. In addition, the influence of multiple bedding planes, is investigated. Changes in pore pressure and permeability due to high pressure injection lasting 2 h were analysed. Results show that in our case during the injection period the fracture reaches the confining formations and if the permeability of those layers is significantly larger than that of the shale, the pore pressure at the extended fracture tip decreases and fracture propagation becomes slower. After shut-in, the pore pressure decreases more and the fracture does not propagate any more. For bedding planes oriented perpendicular to the maximum principal stress direction and with the same elastic properties as the shale formation, results were found not to be influenced by their presence. In such a scenario, the impact of multiple bedding planes on fracture propagation is negligible. On the other hand, a bedding plane softer than the surrounding shale formation leads to a fracture propagation asymmetrical vertically with respect to the centre of the injection fracture with a more limited upward fracture propagation. A pre-existing fault leads to a decrease in fracture propagation because of fault reactivation with shear failure. This results in a smaller increase in injection fracture permeability and a slight higher injection pressure than that observed without the fault. Overall, results of a sensitivity analysis show that fracture propagation is influenced by the stress ratio SR, the permeability kc of the confining formations and the initial permeability kp of the bedding plane more than the other major parameters.

In this study, a numerical manifold method (NMM) model was developed for fully coupled analysis of hydro-mechanical (HM) processes in porous rock masses with discrete fractures. Using an NMM two-cover-mesh system of mathematical and physical covers, fractures are conveniently discretized by dividing the mathematical cover along fracture traces to physical cover, resulting in a discontinuous model on a non-conforming mesh. In this model, discrete fracture deformation (e.g. open and slip) and fracture fluid flow within a permeable and deformable porous rock matrix are rigorously considered. For porous rock, direct pore-volume coupling was modeled based on an energy-work scheme. For mechanical analysis of fractures, a fracture constitutive model for mechanically open states was introduced. For fluid flow in fractures, both along-fracture and normal-to-fracture fluid flow are modeled without introducing additional degrees of freedom. When the mechanical aperture of a fracture is changing, its hydraulic aperture and hydraulic conductivity is updated. At the same time, under the effect of coupled deformation and fluid flow, the contact state may dynamically change, and the corresponding contact constraint is updated each time step. Therefore, indirect coupling is realized under stringent considerations of coupled HM effects and fracture constitutive behavior transfer dynamically. To verify the new model, examples involving deformable porous media containing a single and two sets of fractures were designed, showing good accuracy. Last, the model was applied to analyze coupled HM behavior of fractured porous rock domains with complex fracture networks under effects of loading and injection.

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.

Shallow, heavy oil diatomite reservoirs produced using cyclic steaming are often associated with significant subsidence. In cases where the pore pressure is not allowed to deplete noticeably, observed subsidence suggests a mechanism other than pressure decline is responsible. We perform coupled flow and geomechanics modeling to determine whether thermally induced compaction of the reservoir rock could play an important role in subsidence. First, we model laboratory-scale tests on diatomite samples subjected to mechanical and thermal loads. During these tests, substantial non-recoverable thermal compaction was measured. Using the modified Cam-clay model as a basis, thermally induced compaction is implemented by reducing the size of the yield surface as a function of temperature. This leads to a satisfactory modeling of the test results. Second, this new approach is used to model a symmetric pattern of wells in a generic heavy oil diatomite field produced using cyclic steaming. Results from simulations that consider or neglect thermally induced diatomite compaction show that thermal effects can potentially induce significant inelastic pore volume reduction and substantial subsidence.

An Enhanced Geothermal System (EGS) Demonstration Project is currently underway in the Northwest Geysers. The project goal is to demonstrate the feasibility of stimulating a deep high-temperature reservoir (HTR) (up to 400 °C, 750 °F). Two previously abandoned wells, Prati State 31 (PS-31) and Prati 32 (P-32), were reopened and deepened to be used as an injection and production doublet to stimulate the HTR. The deepened portions of both wells have conductive temperature gradients of 10 °F/100 ft (182 °C/km), produce connate native fluids and magmatic gas, and the rocks were isotopically unexchanged by meteoric water. The ambient temperature meteoric water injected into these hot dry rocks has evidently created a permeability volume of several cubic kilometers as determined by seismic monitoring. Preliminary isotopic analyses of the injected and produced water indicate that 50–75% of the steam from the created EGS reservoir is injection-derived.

Poro-elastic stress and effective stress reduction associated with deep underground fluid injection can potentially trigger shear rupture along pre-existing faults. We modeled an idealized CO2 injection scenario, to assess the effects on faults in the first phase of a generic CO2 aquifer storage operation. We used coupled multiphase fluid flow and geomechanical numerical modeling to evaluate the stress and pressure perturbations induced by fluid injection and the response of a nearby normal fault. Slip-rate dependent friction and inertial effects have been taken into account during rupture. Contact elements have been used to take into account the frictional behavior of the rupture plane. We investigated different scenarios of injection rate to induce rupture on the fault, employing various fault rheologies. Published laboratory data on CO2-saturated intact and crushed rock samples, representative of a potential target aquifer, sealing formation and fault gouge, have been used to define a scenario where different fault rheologies apply at different depths. Nucleation of fault rupture takes place at the bottom of the reservoir, in agreement with analytical poro-elastic stress calculations, depending on injection-induced reservoir inflation and the tectonic stress scenario. For the stress state considered here, the first triggered rupture always produces the largest rupture length and slip magnitude, both of which correlate with the fault rheology. Velocity weakening produces larger ruptures and generates larger magnitude seismic events. Heterogeneous faults have been considered including velocity-weakening or velocity strengthening sections inside and below the aquifer, with the upper sections being velocity-neutral. Nucleation of rupture in a velocity-strengthening section results in a limited rupture extension, both in terms of maximum slip and rupture length. For a heterogeneous fault with nucleation in a velocity-weakening section, the rupture may propagate into the overlying velocity-neutral section, if the extent of velocity-weakening and associated friction drop are large enough.

In this paper, we summarize the results of coupled thermal, hydraulic, and mechanical (THM) modeling in support of the Northwest Geysers EGS Demonstration Project, which aims at enhancing production from a known High Temperature Reservoir (HTR) (280–400 °C) located under the conventional (240 °C) geothermal steam reservoir. The THM modeling was conducted to investigate geomechanical effects of cold-water injection during the stimulation of the EGS, first to predict the extent of the stimulation zone for a given injection schedule, and then to conduct interpretive analyses of the actual stimulation. By using a calibrated THM model based on historic injection and microseismic data at a nearby well, we could reasonably predict the extent of the stimulation zone around the injection well, at least for the first few months of injection. However, observed microseismic evolution and pressure responses over the one-year stimulation-injection revealed more heterogeneous behavior as a result of more complex geology, including a network of shear zones. Therefore, for an interpretive analysis of the one-year stimulation campaign, we included two sets of vertical shear zones within the model; a set of more permeable NW-striking shear zones and a set of less permeable NE-striking shear zones. Our modeling indicates that the microseismic events in this system are related to shear reactivation of pre-existing fractures, triggered by the combined effects of injection-induced cooling around the injection well and rapid (but small) changes in steam pressure as far as a kilometer from the injection well. Overall, the integrated monitoring and modeling of microseismicity, ground surface deformations, reservoir pressure, fluid chemical composition, and seismic tomography depict an EGS system hydraulically bounded by some of the NE-striking low permeability shear zones, with the more permeable NW-striking shear zone providing liquid flow paths for stimulation deep (several kilometers) down into the HTR. The modeling indicates that a significant mechanical degradation (damage) inferred from seismic tomography, and potential changes in fracture porosity inferred from cross-well pressure responses, are related to shear rupture in the stimulation zone driven by both pressure and cooling effects.

We present a three-dimensional thermohydromechanical numerical study of the evolution and distribution of the stress tensor within the northwest part of The Geysers geothermal reservoir (in California), including a detailed study of the region around one injection well from 2003 to 2012. Initially, after imposing a normal faulting stress regime, we calculated local changes in the stress regime around injection wells. Our results were compared with previously published studies in which the stress state was inferred from inverting the focal plane mechanism of seismic events. Our main finding is that changes in stress tensor orientation are caused by injection-induced progressive cooling of the reservoir, as well as by the seasonal variations in injection rate. Because of the gravity flow and cooling around a liquid zone formed by the injection, the vertical stress reduction is larger and propagates far below the injection well. At the same time, the horizontal stress increases, mostly because of stress redistribution below and above the cooling area. These two phenomena cause the rotation of the stress tensor and the appearance of a strike-slip regime above, inside, and below the cooling area. The cooling and the associated rotation of the stress regime can play a significant role in the observed long-term deepening of the microseismicity below active injection wells.

In this paper, we use the Seismicity-Based Reservoir Characterization approach to study the spatiotemporal dynamics of an injection-induced microseismic cloud, monitored during the stimulation of an enhanced geothermal system, and associated with the Northwest Geysers Enhanced Geothermal System (EGS) Demonstration project (California). We identified the development of a seismically quiet domain around the injection well surrounded by a seismically active domain. Then we compare these observations with the results of 3-D Thermo-Hydro-Mechanical simulations of the EGS, which accounts for changes in permeability as a function of the effective normal stress and the plastic strain. The results of our modeling show that (1) the aseismic domain is caused by both the presence of the injected cold water and by thermal processes. These thermal processes cause a cooling-stress reduction, which prevent shear reactivation and favors fracture opening by reducing effective normal stress and locally increasing the permeability. This process is accompanied by aseismic plastic shear strain. (2) In the seismic domain, microseismicity is caused by the reactivation of the preexisting fractures, resulting from an increase in injection-induced pore pressure. Our modeling indicates that in this domain, permeability evolves according to the effective normal stress acting on the shear zones, whereas shearing of preexisting fractures may have a low impact on permeability. We attribute this lack of permeability gain to the fact that the initial permeabilities of these preexisting fractures are already high (up to 2 orders of magnitude higher than the host rock) and may already be fully dilated by past tectonic straining.

One of the most important design variables for a geological nuclear waste repository is the temperature limit up to which the engineered barrier system (EBS) and the natural geologic environment can be exposed. Up to now, almost all design concepts that involve bentonite-backfilled emplacement tunnels have chosen a maximum allowable temperature of about 100. °C. Such a choice is largely based on the consideration that in clay-based materials illitization and the associated mechanical changes in the bentonite (and perhaps the clay host rock) could affect the barrier attributes of the EBS. However, existing experimental and modeling studies on the occurrence of illitization and related performance impacts are not conclusive, in part because the relevant couplings between the thermal, hydrological, chemical, and mechanical (THMC) processes have not been fully represented in the models. This paper presents a fully coupled THMC simulation of a nuclear waste repository in a clay formation with a bentonite-backfilled EBS for 1000. years. Two scenarios were simulated for comparison: a case in which the temperature in the bentonite near the waste canister can reach about 200. °C and a case in which the temperature in the bentonite near the waste canister peaks at about 100. °C.The model simulations demonstrate some degree of illitization in both the bentonite buffer and the surrounding clay formation. Other chemical alterations include the dissolution of K-feldspar and calcite, and precipitation of quartz, chlorite, and kaolinite. In general, illitization in the bentonite and the clay formation is enhanced at higher temperature. However, the quantity of illitization is affected by many chemical factors and therefore varies a great deal. The most important chemical factors are the concentration of K in the pore water as well as the abundance and dissolution rate of K-feldspar less important ones are the concentration of sodium and the quartz precipitation rate. In our modeling scenarios, the calculated decrease in smectite volume fraction in bentonite ranges from 1 to 8% of the initial volume fraction of smectite in the 100. °C scenario and 1-27% in the 200. °C scenario. Chemical changes in the 200. °C scenario could also lead to a reduction in swelling stress up to 15-18% whereas those in the 100. °C scenario result in about 14-15% reduction in swelling stress for the base case scenario. Model results also show that the 200. °C scenario results in a much higher total stress than the 100. °C scenario, mostly due to thermal pressurization. While cautions should be taken regarding the model results due to some limitations in the models, the modeling work is illustrative in light of the relative importance of different processes occurring in EBS bentonite and clay formation at higher than 100. °C conditions, and could be of greater use when site specific data are available.

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.

We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dipping fault, with hydraulic fracturing channeled within the fault, during a 3-h hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismic moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-h injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200. m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500. m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.

Free gas migration through the gas hydrate stability zone (GHSZ) and subsequent gas seepage at the seabed are characteristic features in marine gas hydrate provinces worldwide. The biogenic or thermogenic gas is typically transported along faults from deeper sediment strata to the GHSZ. Several mechanisms have been proposed to explain free gas transport through the GHSZ. While inhibition of hydrate formation by elevated salinities and temperatures have been addressed previously in studies simulating unfocused, area‐wide upward advection of gas, which is not adequately supported by field observations, the role of focused gas flow through chimney‐like structures has been underappreciated in this context. Our simulations suggest that gas migration through the GHSZ is, fundamentally, a result of methane gas supply in excess of its consumption by hydrate formation. The required high gas flux is driven by local overpressure, built up from gas accumulating below the base of the GHSZ that fractures the overburden when exceeding a critical pressure, thereby creating the chimney‐like migration pathway. Initially rapid hydrate formation raises the temperature in the chimney structure, thereby facilitating further gas transport through the GHSZ. As a consequence, high hydrate saturations form preferentially close to the seafloor, where temperatures drop to bottom water values, producing a prominent subsurface salinity peak. Over time, hydrates form at a lower rate throughout the chimney structure, while initial temperature elevation and salinity peak dissipate. Thus, our simulations suggest that the near‐surface salinity peak and elevated temperatures are a result of transient high‐flux gas migration through the GHSZ. Key Points: Free gas can migrate through the GHSZ if it is supplied in excess of the consumption by gas hydrate formationEffective gas transport through the GHSZ requires a high gas supply as it is possible in seismic pipe or chimney structures and faultsObserved salinity peaks and temperatures are a result of intermittent high gas fluxes following overpressure buildup and fracturing [ABSTRACT FROM AUTHOR]

We describe the development of a sequential implicit formulation and algorithm for coupling fluid-heat flow, reactive transport, and geomechanics. We consider changes in pore volume from dissolution caused by chemical reactions, in addition to coupled flow and geomechanics. Moreover, we use the constitutive equations for the multiple porosity model for fractured geothermal reservoirs, employing failure-dependent permeability dynamically and updating it every time step. The proposed sequential algorithm is an extension of the fixed-stress split method to chemo-thermo-poro-mechanics, facilitating the use of existing flow-reactive transport and geomechanics simulators. We first validate a simulator that employs the proposed sequential algorithm, matching the numerical solutions with the analytical solutions such as Terzaghi's and Mandel's problems for poro-mechanics and the reference solutions of chemo-poro-mechanics and chemo-thermo-poro-mechanics in the 1D elastic problems. We also perform convergence test, and the proposed algorithm shows fast convergence, when full iteration is taken, and first order accuracy in time for the staggered approach. We then investigate two test cases: 2D multiple porosity elastic and 3D single porosity elastoplastic problems, and explore the differences in coupled flow and geomechanics with and without reactive transport. We find that the change in pore-volume induced by mineral dissolution can impact on fluid pressure and failure status, followed by significant changes in permeability and flow variables, showing strong interrelations between flow-reactive transport and geomechanics. [ABSTRACT FROM AUTHOR]

We recently submitted a full ICDP drilling proposal entitled Drilling Active Faults in Northern Europe (DAFNE). The drilling target is a postglacial fault (PGF) system in North Sweden, the Pärvie fault system (PFS). The PFS is 155 km long, with an apparent throw of up to 25 m (bedrock and soil thickness). The PFS ruptured at the final stage of the Weichselian glaciation, about 10 ka BP, most probably in a great earthquake (Mw=8.0±0.4) triggered by the rapid uplift of Fennoscandia due to relaxation of accumulated stress under the disappearing ice sheet. The PFS is still seismically active; from 2003-2013, 1046 microseismic events were recorded down to ~35 km depth along the fault system. We have identified two drill sites located c. 30 km west of the city of Kiruna. This part of the PFS has been proposed to reflect a flower structure. To understand this complex structure, multiple boreholes, logging, in situ testing and monitoring are required. Two sites, with two boreholes at each site are proposed. The two sites aim at penetrating the east-dipping main fault and the west-dipping subsidiary fault, respectively. Ongoing seismicity is related to both structures. DAFNE has the following scientific objectives:1. To improve insight in both how large intraplate earthquakes are triggered and why seismicity persists for very long time periods in areas of previous large ruptures;2. To reach a better understanding of accumulation and release of strain along a postglacial intraplate fault zone, as well as revealing the consequences of seismicity, brittle deformation and stress on the thermal and hydrogeological regimes and the deep biosphere;3. To improve the understanding of glacial isostatic adjustment (GIA). We anticipate that new data and results from drilling and numerical analyses will support prediction of new postglacial-type seismicity that is expected due to shrinking of ice sheets during current climatic warming at high latitudes (e.g. Greenland, Antarctica, Iceland, Alaska, and major mountain chains); and4. To study the distal effect of the passive margin development along the western Fennoscandian Shield by extending the 3D modelling of temperature, stress and strain in the Nordland area of Norway eastwards to cover the PFS. The PGFs in general and PFS in particular represent a type of intraplate seismicity that is still poorly understood. The project also has high societal relevance regarding assessment of seismic hazard for hydropower- and tailing dams, storage of nuclear waste, and mining. With the aid of scientific drilling, we aim at a comprehensive study of the geology, fault properties, tectonic history, stress field, seismicity, hydrogeology, subsurface life and geothermics of the PFS to address the scientific objectives of the project. [ABSTRACT FROM AUTHOR]