Caprock Integrity and Induced Seismicity from Laboratory and Numerical Experiments

CO2 leakage is a major concern for geologic carbon storage. To assess the caprock sealing capacity and the strength of faults, we test in the laboratory the rock types involved in CO2 storage at representative in-situ conditions. We use the measured parameters as input data to a numerical model that simulates CO2 injection in a deep saline aquifer bounded by a low-permeable fault. We find that the caprock sealing capacity is maintained and that, even if a fault undergoes a series of microseismic events or aseismic slip, leakage is unlikely to occur through ductile clay-rich faults. © 2017 The Authors. Published by Elsevier Ltd.V.V. acknowledges financial support from the “TRUST" project (European Community's Seventh Framework Programme FP7/2007-2013 under grant agreement n. 309607) and from “FracRisk" project (European Community's Horizon 2020 Framework Programme H2020-EU.3.3.2.3 under grant agreement n. 640979). R.M. acknowledges partial support from the Center for Geologic Storage of CO2, an EFRC funded by the U.S. DOE, Office of Science, BES, under Award DE-SC0C12504.Peer reviewe

Geomechanical analysis of the influence of CO2 injection location on fault stability

Large amounts of carbon dioxide (CO2) should be injected in deep saline formations to mitigate climate change, implying geomechanical challenges that require further understanding. Pressure build-up induced by CO2 injection will decrease the effective stresses and may affect fault stability. Geomechanical effects of overpressure induced by CO2 injection either in the hanging wall or in the foot wall on fault stability are investigated. CO2 injection in the presence of a low-permeable fault induces pressurization of the storage formation between the injection well and the fault. The low permeability of the fault hinders fluid flow across it and leads to smaller overpressure on the other side of the fault. This variability in the fluid pressure distribution gives rise to differential total stress changes around the fault that reduce its stability. Despite a significant pressure build-up induced by the fault, caprock stability around the injection well is not compromised and thus, CO2 leakage across the caprock is unlikely to happen. The decrease in fault stability is similar regardless of the side of the fault where CO2 is injected. Simulation results show that fault core permeability has a significant effect on fault stability, becoming less affected for high-permeable faults. An appropriate pressure management will allow storing large quantities of CO2 without inducing fault reactivation. © 2016 Institute of Rock and Soil Mechanics, Chinese Academy of SciencesThe first author acknowledges the support from the “EPFL Fellows” fellowship program co-funded by Marie Curie, FP7 (Grant No. 291771) and partial support from the “TRUST” project of the European Community's Seventh Framework Programme FP7/2007–2013 (Grant No. 309607) and the “FracRisk” project of the European Community's Horizon 2020 Framework Programme H2020-EU.3.3.2.3 (Grant No. 640979). Activities of the second author are sponsored by SCCER-SoE (Switzerland) (Grant No. KTI.2013.288) and Swiss Federal Office of Energy (SFOE) project CAPROCK (Grant No. 810008154). This publication has also been produced with partial support from the BIGCCS Centre (for the third author), performed under the Norwegian research program Centers for Environment-friendly Energy Research (FME). The third author acknowledges the following partners for their contributions: Gassco, Shell, Statoil, TOTAL, ENGIE, and the Research Council of Norway (193816/S60).Peer reviewe

Potential for Fault Reactivation Due to CO2 Injection in a Semi-Closed Saline Aquifer

CO2 injection in extensive saline aquifers that present no faults is unlikely to damage the caprock sealing capacity. In contrast, CO2 injection in closed reservoirs will induce a large pressure buildup that may reactivate the low-permeable faults that bound the reservoir. However, the vast majority of CO2 storage formations will be extensive saline aquifers bounded by a limited number of low-permeable faults. Such storage formations have received little attention and are the focus of this study. We model an extensive aquifer bounded by a heterogeneous low-permeable fault on one side and having open boundaries on the other sides. Simulation results show that the storage formation pressurizes between the injection well and the low-permeable fault, causing total stress changes and effective stress reduction around the fault. These changes lead to yielding of the fault core that is next to the lower half of the storage formation when injecting in the hanging wall. The yield of the fault core would induce a sequence of microseismic events with accumulated seismic moment equivalent to an earthquake of magnitude 1.7, which would not be felt on the ground surface and would not enhance permeability of the ductile clay-rich fault. © 2017 The Authors.V.V. acknowledges support from the ‘EPFL Fellows’ fellowship programme co-funded by Marie Curie, FP7 Grant agreement no. 291771. R.M. activities are sponsored by SCCER-SoE (Switzerland) grant KTI.2013.288 and Swiss Federal Office of Energy (SFOE) project CAPROCK #810008154.Peer reviewe

Evolution of poroviscoelastic properties of silica-rich rock after CO

Injection of CO2 into the subsurface requires consideration of the poromechanical behavior of reservoir rock saturated with aqueous fluid. The material response is usually assumed to be elastic, to avoid consideration of induced seismicity, or viscoelastic, if long-term deformations are needed to be taken into the account. Both elastic and viscous behavior may be influenced by the chemical reactions that are caused by the acidic mixture formed as high-pressure CO2 enters the pore space saturated with aqueous fluid. In this study, we conduct laboratory experiments on a fluid-saturated porous rock - Berea sandstone, and evaluate its poromechanical properties. Subsequently, the specimens are treated with liquid CO2 for 21 days and the corresponding variations in their properties are determined. The constitutive model considering the elastic time-dependent behavior of porous rock is validated by comparing the measured and predicted specimen deformation. Presented data indicate that the effect of CO2 injection on the long-term response is more significant compared to the short-term response. It is suggested for the constitutive models that predict long-term reservoir behavior during CO2 storage to include not only the poroelastic response and its change due to treatment, but also the time-dependent deformation and its evolution caused by the changes in chemistry of the pore fluid

Geomechanics and Fluid Flow in Geothermal Systems

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

Dilatant hardening of fluid-saturated sandstone

The presence of pore fluid in rock affects both the elastic and inelastic deformation processes, yet laboratory testing is typically performed on dry material even though in situ the rock is often saturated. Techniques were developed for testing fluid-saturated porous rock under the limiting conditions of drained, undrained, and unjacketed response. Confined compression experiments, both conventional triaxial and plane strain, were performed on water-saturated Berea sandstone to investigate poroelastic and inelastic behavior. Measured drained response was used to calibrate an elasto-plastic constitutive model that predicts undrained inelastic deformation. The experimental data show good agreement with the model: dilatant hardening in undrained triaxial and plane strain compression tests under constant mean stress was predicted and observed

CO2 Injection Effect on Geomechanical and Flow Properties of Calcite-Rich Reservoirs

Geologic carbon storage is considered as a requisite to effectively mitigate climate change, so large amounts of carbon dioxide (CO2) are expected to be injected in sedimentary saline formations. CO2 injection leads to the creation of acidic solution when it dissolves into the resident brine, which can react with reservoir rock, especially carbonates. We numerically investigated the behavior of reservoir-caprock system where CO2 injection-induced changes in the hydraulic and geomechanical properties of Apulian limestone were measured in the laboratory. We found that porosity of the limestone slightly decreases after CO2 treatment, which lead to a permeability reduction by a factor of two. In the treated specimens, calcite dissolution was observed at the inlet, but carbonate precipitation occurred at the outlet, which was closed during the reaction time of three days. Additionally, the relative permeability curves were modified after CO2–rock interaction, especially the one for water, which evolved from a quadratic to a quasi-linear function of the water saturation degree. Geomechanically, the limestone became softer and it was weakened after being altered by CO2. Simulation results showed that the property changes occurring within the CO2 plume caused a stress redistribution because CO2 treated limestone became softer and tended to deform more in response to pressure buildup than the pristine rock. The reduction in strength induced by geochemical reactions may eventually cause shear failure within the CO2 plume affected rock. This combination of laboratory experiments with numerical simulations leads to a better understanding of the implications of coupled chemo-mechanical interactions in geologic carbon storage.Research by K. Kim and R. Makhnenko was funded as part of the Center for Geologic Storage of CO2, an Energy Frontier Research Center funded by the U.S. Department of Energy (DOE), Office of Science, Basic Energy Sciences (BES), under Award #DE-SC0C12504. Financial support for V. Vilarrasa was from the “ZoDrEx” project, which has been subsidized through the ERANET Cofund GEOTHERMICA (Project No. 731117), from the European Commission and the Spanish Ministry of Economy, Industry and Competitiveness (MINECO).Peer reviewe

Inhomogeneous fault stability due to fluid injection

Forecasting and mitigating induced seismicity requires understanding of the underlying physical processes. Poromechanical and thermal effects on stresses and shear slip stress transfer play a non-negligible role that has challenged the classical interpretation in which induced seismicity is caused exclusively by pressure buildup (De Simone et al., 2017). In this contribution, we analyze how the stress changes induced as a result of fluid injection affect fault stability. We perform fully coupled hydro-mechanical simulations of fluid injection into a saline aquifer bounded above and below by low-permeable clay-rich rock and intersected by a low-permeable steep fault. Simulation results show that maintaining a constant injection rate leads to a progressive reservoir pressurization on the side of the fault where injection takes place (Fig. 1a). Given the low-permeability of the fault core, pressure buildup is negligible on the other side of the fault. These pore pressure changes cause strong variations in the total stresses controlled by rock stiffness around the fault. Deviatoric stress changes are controlled by stress balance from the two sides of the fault: the upper part of the reservoir, juxtaposed to the stiffer reservoir on the right, has a lower increase in the deviatoric stress than the lower part, which is juxtaposed to the more compliant caprock. This implies increased fault stability in the upper part and decreased fault stability in the lower part (Fig, 1d). As highlighted by our results, fault stability is: i) non-homogeneous within the whole fault and ii) controlled by poromechanical stress changes as much as by pressure buildup.V.V. would like to acknowledge funding from the European Research Council (ERC) under European Union’s Horizon 2020 research and innovation programme (grant agreement No 801809), and CSIC through the Intramural project 201730I100Peer reviewe

Paul-Mohr-Coulomb failure surface of rock in the brittle regime

The Paul-Mohr-Coulomb failure criterion includes the intermediate principal stress sigma(II) and friction angles at the limiting stress states of sigma(II)= sigma(III) and sigma(II) = sigma(I), where sigma(I) and sigma(III) are major and minor principal stresses. Conventional triaxial compression (sigma(II) = sigma(III)), extension (sigma(II) = sigma(I)), and plane strain (sigma(I) not equal sigma(II) not equal sigma(III)) experiments were performed on dry rock. The failure data were plotted in principal stress space, and material parameters were determined in the context of two internal friction angles and the theoretical uniform triaxial (all-around equal) tensile strength. Assuming isotropy, the triaxial compression and extension results were used to construct a six-sided pyramidal failure surface, and the extension friction angle was larger than the compression friction angle, a sufficient but not necessary condition of the intermediate stress effect. To capture the behavior of the rock in multiaxial loading, the Paul-Mohr-Coulomb criterion was extended to form a 12-sided pyramid with best fit planes