ERE5.5

Understanding rock failure is key for the safe and efficient development of the subsurface. Gas storage (CO₂, H₂ or CH₄), production of geothermal energy and the traditional extraction of hydrocarbons means fluid injection or extraction. These processes change the local stress state, but also local temperature or chemistry. Such use of the subsurface is about either keeping fluid where it is (storage) or making sure fluids come out with a sufficient but still safe rate. Since fault rocks are in many cases important fluid transport pathways, this needs a careful and complete understanding of how rocks fail. Therefore, a thorough understanding of the stages of deformation leading to failure is key, as well as any potential differences for different rock types and failure modes. We performed uniaxial compressive and triaxial experiments on limestone and sandstone to investigate the hydro-mechano-chemical coupling in rock failure, using active and passive acoustics to monitor the failure behaviour. All experiments are done at room temperature.

Using active acoustics for first arrival times is an established technique. We use here the more novel coda-wave interferometry technique to track deformation in triaxial tests at different confining pressures in sandstones and limestone, which deform respectively in a fully brittle or a semi-ductile manner. This shows that the first signs of failure can be picked up before the yield point, i.e. before the time it is picked up by any of the traditional bulk stress-strain signals used in experimental rock deformation. In uniaxial compressive experiments on the same brittle sandstone samples we show that the loading pattern can affect the final strength but also the maximum acoustic emission amplitude. Cyclic loading tends to systematically reduce the magnitude of the largest induced seismic event, whilst simultaneously also promoting more complex fracture patterns and disintegration. This implies that the risk of induced seismicity can be mitigated by changing the loading pattern in subsurface operations. Finally, we show that for reactive rocks under the right pressure and temperature conditions, changing the chemistry can have an effect on rock strength, where the effects depend on the internal rock structure. This research increases the understanding of rock failure and show the potential of monitoring for a safe and efficient development of the subsurface.

How to cite: Pluymakers, A., Veltmeijer, A., Naderloo, M., Kortram, J.-D., and Barnhoorn, A.: Hydro-mechano-chemical coupling in rock failure, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-7156, https://doi.org/10.5194/egusphere-egu22-7156, 2022.

The fluid's pore pressure represents the main geomechanics parameter to consider while planning for drilling operations and during production. Actually, a good understanding of overpressure origins leads to better characterize of the pore pressure, which materialized by the suggestion of several models to predict pore pressure. Therefore, the successful technical achievement of a drilling program is judged by the sustainable integrity of the well i.e. sealing effectiveness between different reservoirs. As a result, this should guarantee long-term water resources protection, rational production, and sustainable development.

                The studied cases (CI-11 and OKN-32 wells) reflect the direct effect of the integrity failure of the cased hole, leading to the groundwater and ecological safety of the major transboundary aquifers system in North Africa. This aquifer is known as the North-Western Sahara Aquifer System (NWSAS), which is shared between Tunisia, Algeria, and Libya. It's hosting huge reserves of non-renewable water, in an arid climate region. The assessment of the wells Jemna CI-11 in Tunisia and the Berkaoui OKN-32 in Algeria have concluded the integrity loss of the wellbore. These issues led to CI mass-water flowing behind the casing from the CI to the CT aquifers which characterize an internal blowout where water flows from the over-pressurized CI groundwater to the shallower CT groundwater. First, the case of the Haoud Berkaoui in 1984, (OKN-32 well) has induced a CI waters flow behind the casing causing the CT water resource contamination, which is ended with a surface crater collapse over a diameter of 320 m. Second, a quite similar accident happened in Jemna in 2015, (CI-11 well) where evidence of water flowing from CI to CT through a leaked-off casing has been discovered. Jemna CI-11, Berkaoui OKN-32, and probably many other ongoing similar accidents, could be classified as regional ecological disasters by massive water resources losses and contamination. The actual situation is far from being under control and the water contamination risk remains at a very high level.

                Finally, due to unsuitable drilling programs, drilling operation problems, and/or production casing corrosion, we suspect that dozens of oil and water wells may be involved in well integrity failure affecting the NWSAS groundwater resource. And since, we cannot diagnose easily internal blowout unless widespread contamination happened, we strongly recommend (1) a regional investigation and risk assessment plan which might offer better tools to predict and detect earlier well-bore isolation issues and (2) special attention to the cement bond settlement, evaluation, and preventive logging for existing wells to ensure effective sealing between the vulnerable water tables. Besides, in the CI-11 well accident, the recovery program was not efficient and there was no clear action plan. This increases the risk of action failure or time waste to regain control of the well. Consequently, we suggest preparing a clear and efficient action plan for such accidents in order to reduce their ecological consequences. This needs a further technical detailed study of drilling operations and establishment of the suitable equipment/action plan to handle blowout and annular production accidents.

How to cite: Khalfi, C., Ouhaibi, C., Ahmadi, R., and Dassi, L.: Role of the pore pressure profile on the protection of wellbore integrity and the groundwater: Case studies of well integrity issues of CI-11, in southern Tunisia, and OKN-32 in Algeria., EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-278, https://doi.org/10.5194/egusphere-egu22-278, 2022.

Fluid extraction from subsurface reservoir sandstones frequently results in surface subsidence and induced seismicity, as observed in the Groningen Gas field (Netherlands). The cause lies in reservoir compaction driven by pressure depletion and the associated increase in effective overburden stress. Compaction in sandstones often includes elastic and significant inelastic components. The inelastic part is at least partly due to rate- or time-dependent processes, such as intergranular sliding or stress corrosion cracking. However, few mechanism-based rate/time-dependent compaction laws exist, despite the need to evaluate the impact of reservoir exploitation on field time scales (1-100 years). To help bridge this gap, we systematically investigated the effect of loading strain rate in the range from 10^-3 to 10^-9 s^-1 in a series of triaxial compression experiments performed on water-saturated Bleurswiller sandstone samples with porosities of 21.07±0.15 % and composed of 66 % quartz, 28 % feldspar and 4 % clay. This material was chosen because of similarity to the Groningen sandstone but greater uniformity. We explored conditions of confining pressure (39 MPa), pore pressure (10 MPa) and temperature (100 °C) corresponding to in-situ values for Groningen. Axial strains up to 3 % were imposed. Our results showed combined elastic plus strain hardening (inelastic) loading behavior, up to a peak stress reached at 0.8-1.0 % strain, followed by strain softening towards a steady residual stress attained at 1.5-2.0 % strain. A systematic lowering of stress-strain curve levels was observed with decreasing strain rate, such that peak and residual stresses decreased respectively from 88 and 74 MPa at 10^-3 s^-1 to 70 and 61 at 10^-9 s^-1. No effect of loading rate is observed at differential stresses below ~ 50% of peak stress. At higher differential stresses up to peak, net sample stiffness (stress-strain curve slope) decreases with decreasing strain rate. Using the curve obtained at 10^-3 s^-1 as a reference, we determined the excess strains measured at rates of 10^-4 to 10^-9 s^-1 at fixed differential stresses up to the peak. By extrapolating this empirical relation to field strain rates associated with gas production in Groningen (i.e. 10^-12 s^-1), it is estimated that ~30 % more compaction strain is developed under field conditions, at current differential stresses in the field (i.e. ~ 60 % peak stress), than in laboratory experiments at rates of 10^-3 to 10^-5 s-1. Additional experiments at varying temperature and confining pressure show sensitivities that suggest that the observed effect of strain rate is likely associated with a combination of time-dependent grain failure by stress corrosion and intergranular sliding. Work is in progress to assess the effect of varying mineralogy by conducting similar experiments on clay-free, quartz-rich Bentheimer sandstone. Our results show that time-dependent inelastic deformation plays an important role in estimating reservoir deformation and associated change in stress associated with fluid production from sandstone reservoirs, like the Groningen reservoir. Such effects could lead to underestimation of surface subsidence and induced seismicity, if not adequately accounted for. The present experiments thus provide important data for testing current models for rate-dependent reservoir compaction.   

How to cite: Shinohara, T., Spiers, C., and Hangx, S.: Effect of loading rate on mechanical behavior and deformation mechanisms in clay-bearing sandstones, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2425, https://doi.org/10.5194/egusphere-egu22-2425, 2022.

Predicting the growth of fluid-driven fractures in geological systems is essential for the sustainable and efficient engineering of oil and gas reservoirs. The linear elastic hydraulic fracture mechanics (LHFM), which combines the linear elastic fracture mechanics and lubrication theory, has described well the fracture growth in brittle materials. However, the quasi-brittle nature of reservoir rocks may result in deviations of the fracture propagation from LHFM predictions. We have experimentally investigated the propagation of hydraulic fractures in quasi-brittle rocks under true triaxial stress conditions. We have performed HF injections in 250x250x250 millimeters Zimbabwe gabbro samples in the toughness-dominated growth regime. We use active acoustic monitoring to measure the evolution of fracture radius from diffracted waves and estimate fracture width from transmitted waves (Liu et al., 2020). Assuming a radial and uniformly pressurized crack, we find that LHFM predictions overestimate fracture radius inverted from diffracted acoustic waves but underestimate the measured injection fluid pressure. Using the same radial uniformly pressurized linear elastic fracture model, we also estimate an apparent toughness from the measured fracture radius and pressure. This estimated apparent toughness is not constant and tends to increase with fracture extent in some cases up to a constant value. We also obtain another estimate of fracture toughness from fracture width back-calculated from transmitted waves for a few snapshots of the fracture evolution. These two estimates of the fracture apparent toughness are mostly consistent, although higher values are obtained when the estimation is based on pressure measurement. We also observe an attenuation of transmitted waves across the fracture plane prior to the arrival of the fracture front obtained from diffracted waves. This allows us to estimate a process zone size in the range of two to six centimeters (depending on experiments). In addition, post-test micro-CT images reveal the presence of a microscale fracture path with some 3D crack branches and bridges. The thickness of such a crack band is a few millimeters on par with both grain size and the roughness of the fracture surface measured after the test. These experiments document an increase of the process zone size at the early stage, which stabilizes afterward in some of the experiments. It is important to note that complete separation of scales between fracture radius, process zone, and sample size is hardly achieved in these experiments. A non-negligible influence of the process zone may thus explain the reported deviation from LHFM predictions in gabbro. No effect of the minimum confining stress was visible in the range investigated here (0 to 10 MPa). The applied minimum stresses were always smaller than the reported peak tensile strength for this rock, a domain where the effect of the quasi-brittle nature of rocks is not anticipated to be significant based on recent theoretical results (Garagash, 2019; Liu & Lecampion 2021).

How to cite: Liu, D. and Lecampion, B.: Does the linear hydraulic fracture mechanics predict well the fracture growth in quasi-brittle rocks under laboratory conditions?, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-3445, https://doi.org/10.5194/egusphere-egu22-3445, 2022.

The increasing emission of greenhouse gases and increasing demand for energy supply are reasons to investigate geothermal energy systems where scCO₂ is the working fluid. However, the complex dissolution and reaction of minerals during the heat production processes affect the performance of geothermal reservoirs. Thus, a comprehensive numerical model that includes the Thermal-Hydraulic-Chemical (THC) coupled physical-chemical processes was implemented in the open-source simulator DuMu^X, to model the phase displacement, chemical dissolution, heat transport, and mineral reactions. The aim is to investigate the influence of these parameters on the overall geothermal reservoir performance. More precisely, this study investigates the effects of salt precipitation, mineral reactions, injection rate, injection temperature, and geothermal reservoir size on heat production rate and scCO₂ sequestration. The simulation results show that the scCO2- calcite reaction decreases the reservoir heat production rate but increase the sequestration of scCO₂. Moreover, its effects are proportional to the scCO₂ injection rate but inversely proportional to the geothermal reservoir size. On the other hand, the dissolution of scCO₂ in brine has the same influence as the reaction between scCO₂ and calcite, benefiting the CO₂ sequestration but minimizing the heat production rate of the geothermal reservoirs. Furthermore, the sensitivity analysis presents that the influence of chemical dissolution and mineral reactions are only significant when the injection rate is large and the reservoir size is small.

How to cite: Zhou, D., Tatomir, A., and Sauter, M.: Numerical investigation of the effects of chemical dissolution and mineral reaction on reservoir performances in CO2-plume geothermal systems , EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6622, https://doi.org/10.5194/egusphere-egu22-6622, 2022.

Wormholes are an effective fluid conduit that dominate the flow path in karst aquifers and are artificially induced in geo-energy applications through acid injection. As acidic fluids infiltrate geologic formations, they react with the minerals in the formation. The reaction localizes and forms a dendritic dissolution pattern under certain conditions, known as the reaction infiltration instability. This instability is instigated by material heterogeneities in most computational models. However, studies have demonstrated that injection of water into a homogeneous plaster can initiate and grow wormholes. In this study, we show that material heterogeneities suppress the wormhole growth in carbonate rocks compared with a homogeneous counterpart. Wormholes were numerically simulated through injection of a strong acid (hydrochloric acid) under both homogeneous and heterogeneous permeability fields using a phase-field approach. The phase-field variable represents calcite dissolution in a diffused manner and is coupled with a reactive flow model assuming convective and diffusive acid transport in the liquid phase and significantly high surface reaction rate, which emulate typical high-rate matrix acidizing treatments in carbonate reservoirs. Heterogeneous permeability fields localize the flow in high-permeability domains and enhance the splitting and branching of wormholes. The length of the dominant wormholes can be suppressed as an increasing amount of acid infiltrates into the branched wormholes. Our findings indicate that material heterogeneities should not be treated as a trigger for wormholes in the numerical simulation but as one of the parameters to control their nucleation and growth. 

How to cite: Furui, K. and Yoshioka, K.: A Numerical Study of Wormhole Formation and Growth in Homogeneous and Heterogeneous Carbonate Rocks, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-8971, https://doi.org/10.5194/egusphere-egu22-8971, 2022.

Hydraulic stimulation of deep geothermal reservoirs is necessary in order to establish economical flow rates between the injector and producer wells. Previous field experience in deep crystalline reservoirs have highlighted the importance to stimulate the well by zones in order to create several fractures along the well instead of carrying out a single large stimulation which typically results in the reactivation of only a few fractures along the open-hole section – thus resulting in poor reservoir coverage and low flow transmissivity. Localized hydraulic stimulation can be performed via packer-systems, and although different in their details, share similarities with stimulation operations performed in unconventional oil and gas reservoirs. The main differences are that i) propping agents are not typically used in crystalline geothermal reservoirs, ii) the injection pressure often remains lower than the minimum in-situ stress and iii) the long-term increase of permeability relies on the self-propping effect associated with the shear dilatant behaviour of pre-existing fractures. The type of fractures propagated during hydraulic stimulation thus exhibit both shear and tensile modes of deformation (different than the purely tensile hydraulic fractures).

Physics-based models are necessary in order to design the injection sequence and are typically used in conjunction with uncertainty analysis. We report our developments of  two and three-dimensional numerical models for the hydraulic stimulation of pre-existing fractures accounting for both shear and opening modes of deformation. The fracture behavior is modelled via a non-associated Mohr-Coulomb frictional elasto-plastic law with possible weakening/hardening of friction and dilatancy with slip, while the host rock is assumed linearly elastic. The fluid flow behaviour of the fracture accounts for opening and the associated permeability / storativity changes (with the possibility to use different type of permeability law). We solve in a fully coupled manner the resulting non-linear moving boundary hydromechanical problem.

We present several verification tests for the growth of a frictional shear crack growth in the plane of a pre-existing frature under the injection of fluid at constant rate in both 2D and 3D. Especially, we compare our numerical results with recent analytical solutions for the case of constant friction and constant hydraulic properties of the pre-existing fracture. We then discuss several examples combining shear dilatancy and its effect on flow properties as well as the possible tensile opening of the pre-existing stimulated fracture. Accuracy, robustness and numerical performance – critical for the use of the solver for engineering design - will be discussed as well as future improvements.

This work is sponsored by Geo-Energie Suisse A.G. and the Swiss Federal Office of Energy.

How to cite: Lecampion, B., Sáez, A., and Fakhretdinova, R.: 2D & 3D numerical modeling of fluid-driven frictional crack growth for geothermal hydraulic stimulation  , EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-11543, https://doi.org/10.5194/egusphere-egu22-11543, 2022.

The mechanical behavior of geomaterials depends primarily on their microstructure and in particular the geometry of their pores. This microstructure and its evolution in time due to deformation or chemical transformations also strongly affects the thermo-hydro-mechanical-chemical (THMC) processes in these porous materials. In the last decades, the development of micro-computed tomography has allowed to obtain accurate images of the rock-microstructures and how they evolve subjected to various factors. Many studies have used these 3D geometries of the porous space to characterize primary properties that depend on the microstructure, such as porosity, permeability or elastic moduli, by numerically solving field equations on µCT scan images of rock. For most projects of energy production or waste storage in geological media though, rocks eventually reach their limit of elasticity and the complementary plastic properties are needed to describe the full mechanical behaviour. In this contribution, we will show how we can assess the mechanical behavior of geomaterials in the long-term by solving nonlinear equations directly on realistic microstructures. First, we will discuss the necessary morphometric invariants that can be used in an upscaled constitutive law and show how we can predict the yield surface and its evolution with the chemical alteration of the rock from µCT scan images. Then, a phase field model that allows to simulate interface evolution is applied to investigate pressure solution creep at the grain scale and how it is influenced by microstructural geometry and catalyzing/inhibiting effects like temperature or clay content.

How to cite: Rattez, H., Guével, A., Lesueur, M., and Veveakis, M.: Influence of chemo-mechanical processes and microstructural geometry on the mechanical behavior of geomaterials, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-11737, https://doi.org/10.5194/egusphere-egu22-11737, 2022.