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Decision-making in the area of coastal adaptation is facing major challenges due to ambiguity (i.e., deep uncertainty) pertaining to the selection of a probability model for sea level rise (SLR) projections. Possibility distributions are mathematical tools that address this type of uncertainty since they bound all the plausible probability models that are consistent with the available data. In the present study, SLR uncertainties are represented by a possibility distribution constrained by likely ranges provided in the IPCC Fifth Assessment Report and by a review of high-end scenarios. On this basis, we propose a framework combining probabilities and possibilities to evaluate how SLR uncertainties accumulate with other sources of uncertainties, such as future greenhouse gas emissions, upper bounds of future sea level changes, the regional variability of sea level changes, the vertical ground motion, and the contributions of extremes and wave effects. We apply the framework to evaluate the probability of coastal flooding by the year 2100 at a local, low-lying coastal French urban area on the Mediterranean coast. We show that when adaptation is limited to maintaining current defenses, the level of ambiguity is too large to precisely assign a probability model to future flooding. Raising the coastal walls by 85 cm creates a safety margin that may not be considered sufficient by local stakeholders. A sensitivity analysis highlights the key role of deep uncertainties pertaining to global SLR and of the statistical uncertainty related to extremes. The ranking of uncertainties strongly depends on the decision-maker’s attitude to risk (e.g., neutral, averse), which highlights the need for research combining advanced mathematical theories of uncertainties with decision analytics and social science.

To provide quantitative data for the development of underground hydrogen storage in porous sedimentary rocks, capillary pressures and relative permeabilities have been measured for the hydrogen–water system. The tests have been performed on a Triassic sandstone. Two potential underground hydrogen storage conditions (“shallower”: 55 bar, 20 $$^{\circ }\hbox {C}$$ and “deeper”: 100 bar, 45 $$^{\circ }\hbox {C}$$ ) have been investigated. Capillary pressure curves have been measured following a modified semi-dynamic technique. The data have been combined with mercury injection capillary pressure measurements to derive a model for capillary pressure valid over almost the entire water saturation range. Interfacial tensions and contact angles for the hydrogen–water system have been also derived. Relative permeability curves measured with the steady-state technique yield low values for minimum water saturations of $$\sim $$ 40%. When combined with the capillary pressure data, the relative permeability of hydrogen in sandstone can be evaluated for almost the total range of water saturation. Capillary numbers calculated for our relative permeability experiments indicate a capillary-limited flow regime for the hydrogen–water system. Despite the two differing sets of conditions investigated and this flow regime, the relative permeability curves stay very close from each other, an effect attributed to the almost constant viscosity of hydrogen under our pressure and temperature conditions. This is in contrast with other fluid pairs (e.g., $$\hbox {CO}_{2}$$ –water system) where capillary numbers can strongly vary with pressure and temperature. Similarly, capillary pressure data vary little between the experimental conditions. The interpretation of the results would suggest that the relative permeability and capillary pressure results from this study are applicable to a wide range of pressure and temperature conditions.

A new in situ experiment is proposed for observing and understanding well integrity evolution, potentially due to changes that could occur during a well lifetime. The focus is put on temperature and pressure stresses. A small section of a well is reproduced at scale 1:1 in the Opalinus Clay formation, representative of a low permeable caprock formation (in Mont Terri Underground Rock Laboratory, Switzerland). The well-system behavior is characterized over time both by performing hydro-tests to quantify the hydraulic properties of the well and their evolution, and sampling the fluids to monitor the chemical composition and its changes. This paper presents the well integrity assessment under different imposed temperature (17–52°C) and pressure (10–28 bar) conditions. The results obtained in this study confirm the ability of the chosen design and observation scale to estimate the evolution of the well integrity over time, the characteristics of the flow along the well-system and the reasons of the observed evolution. In particular, the estimated effective well permeability is higher than cement or caprock intrinsic permeability, which suggest preferential flow pathways at interfaces especially at the very beginning of the experiment; the significant variations of the effective well permeability observed after setting pressure and temperature stresses indicate that operations could influence well integrity in similar proportions than the cementing process.

On a geological carbon dioxide storage site, wells (decommissioned or active) drilled through low-permeable caprock are potential connections between the CO2 storage reservoir and overlying sensitive targets like aquifers. The integrity of wells over time is therefore essential for the fluids confinements (brine with or without dissolved CO2 or buoyant gaseous CO2). Well integrity can be defined as its capacity to maintain the isolation of fluids in the subsurface reservoirs. To ensure this isolation, the well casing and the caprock are bonded by a cement sheath; after abandonment, a cement plug is used to avoid upward migration within the casing. However, according to the literature wellbore integrity might be compromised by a) operational defects (during the drilling and cementing processes, during the operations where pressure and temperature changes can modify stress conditions, during the abandonment process) or b) chemical changes especially in the context of CO2 storage where different chemical environments can be possibly found. The evolution of the well integrity is therefore a complex combination of several physical processes (hydrological, thermal, mechanical and chemical at least) on the different materials and elements (formation, cement, casing, interfaces, annuli). The issue addressed in this study is the behaviour of the complete wellbore system in different conditions and especially under influence of CO2. An in situ experiment has been designed and is being run in an underground rock laboratory (Mont Terri, Switzerland) at an intermediate scale between the laboratory experiments (which offer the opportunity to assess specific phenomena over time) and field observations (which allow an assessment of the entire system in subsurface at a specific time). The purpose is here to follow the evolution of the integrity of the whole well system both for hydrogeological and geochemical aspects. Modelling and lab experiments, including material characterization are performed in parallel to enable a better interpretation and understanding of the observations. The experimental setup has been designed as follows: a small section of a wellbore is reproduced in the Opalinus Clay of the underground rock laboratory (caprock-like formation) at scale 1:1 (5.5 '' casing and Ø198 mm borehole), using carbon steel for the casing and class G cement. Below and above the well section, two different intervals have been designed for a continuous monitoring of the pressure and temperature conditions or for fluid injection and extraction (for fluid sampling for instance). The experimental protocol contains several stages: 1- Drilling, relaxation and well completion; 2- Initial state characterization; 3- Temperature increase in the system and characterisation; 4- Injection of pore water with dissolved CO2 and tracers, and characterization. The characterization of the system includes both performing hydro-tests (continuous and constant-head tests) to quantify the hydraulic properties of the well and their evolution over time, and sampling the fluids to analyse the geochemical composition and changes. Stages 1, 2 and 3 are now completed and stage 4 is in progress. The first results (of stage 2 and 3) confirm the ability of the chosen design to assess well integrity over time. It also shows first trends in the evolution of integrity especially under influence of the temperature: the equivalent permeability of the wellbore decreased significantly during that stage, improving the well integrity. Three modelling methods are used to predict the results of the experiment or to use the recorded data: 1) flow and transport modelling, 2) geochemical modelling, and 3) reactive transport modelling (TOUGH2 used for 1, and PhreeqC and TOUGHREACT for 2 and 3). Flow modelling has been associated with the hydraulic tests in order to quantify the well integrity in terms of equivalent permeability during stage 2 and 3. Temperature effects have been included in the models to understand the changes that occurred in terms of effective permeability during stage 3. Geochemical models have been developed to evaluate the validity of chemical sealing as a potential explanation for the increase of well integrity observed during stage 3. The models are also used as predictive tools on the potential evolutionary scenarios for stage 4, regarding water chemistry variations and mineralogical changes. They have been notably useful to calibrate the conditions of the dissolved CO2 in terms of tracers used, and of sampling and in-line fluid analysis protocol. Each of those models will be progressively refined during the CO2-dissolved injection (stage 4) with the aim of aiding the interpretation of the observed processes and phenomena. Finally this field experiment-modelling integrated framework is completed by laboratory characterizations and experiments (in autoclave principally) carried out to provide input data for the modelling with regards to cement, caprock and their reactivity with pore water and CO2.

In this study, we propose to evaluate CO2-brine characteristics using core flooding experiment results with magnetic resonance (MR) imaging and a 1D numerical modelling approach along with a perspective on the role of CO2-brine characteristics on storage efficiency at the reservoir scale. MRI can be used to understand the pore structure and the flow characteristic of the drainage process more directly. The relative permeability curve which is the key parameter to field scale simulation can be obtained by the experiments. 1D numerical modelling is conducted to understand the results observed experimentally and the associated processes by using the parameters measured during the experiments. The modelling can explain the observed differences with the experiment through a sensitivity analysis and propose several set of parameters allowing a good match between experiments and models (history matching). It is shown that the combination method between the experiments and the modelling is a suitable method to understand the mechanism of CO2 geological storage. Moreover, the experiments can provide the validation to the modelling which is the important tool to predict the CO2 migration underground.

Industrial-scale CO2 injection into deep aquifers might induce far-field pressure perturbations on the basin scale, potentially impacting other underground uses present within the same aquifer formation. In the present paper, we investigate an approach to trace back the area of elevated pressure induced by CO2 storage operations through an injection strategy in a cyclic manner over time. In this manner, the CO2 injection-induced pressure field is characterized by a low magnitude harmonic signature very specific to the considered CO2 storage, the frequency being chosen as different to naturally fluctuating phenomena or other anthropogenic underground activities. We rely on the combination of de-trending and FFT technique to detect the harmonic pattern associated the CO2 storage injections. We apply the methodology on synthetic pressure signal numerically generated using a typical injection scenario in the Paris basin case. On this basis, we discuss how trace back the CO2 storage site causing the pressure impact, in particular regarding the existing sources of noise.

This study aims at investigating the role played by the overlying aquifer formation as a safety barrier in case of CO 2 leakage accumulation (i.e. CO 2 accumulated in an overlying aquifer after its leakage from the CO 2 storage reservoir) by focusing on its natural capacity to prevent any further upward migration. Based on numerical simulations performed using TOUGH2/ECO2N incl. hysteretic module, we assess the processes influencing the quantity of mobile CO 2 within the leaking plume and perform a sensitivity analysis to point out the key-parameters and conditions for an efficient natural trapping by dissolution and residual trapping. Additional simulations of a leak - active remediation scenario on a complete system (storing reservoir connected to an overlying aquifer) show the importance of the natural trapping capacity of the overlying aquifer. This capacity could be integrated in the mitigation strategy, associating natural and engineered safety barriers. Gaining more knowledge on these formations can support first estimations of this natural capacity, and hence can help building the corrective measure plan and designing potential interventions during operations.

International audience; Carbon storage in saline formations is considered as a promising option to ensure the necessary decrease of CO2 anthropogenic emissions. Its industrial development in those formations is above all conditioned by its safety demonstration. Assessing the evolution of trapped and mobile CO2 across time is essential in the perspective of reducing leakage risks. In this work, we focus on residual trapping phenomenon occurring during the wetting of the injected CO2 plume. History dependent effects are of first importance when dealing with capillary trapping. We then apply the classical fractional flow theory (Buckley-Leverett type model) and include trapping and hysteresis models; we derive an analytical solution for the temporal evolution of saturation profile and of CO2 trapped quantity when injecting water after the gas injection ("artificial imbibition"). The comparison to numerical simulations for different configurations shows satisfactory match and justifies, in the case of industrial CO2 storage, the assumptions of incompressible flow with no consideration of capillary pressure. The obtained analytical solution allows the quick assessment of both the quantity and the location of mobile gas left during imbibition.

The behaviour of the injected CO2 on the long term is of primary importance and numerous authors have pointed out the essential role of trapping mechanisms in the evolution of the storage. In terms of safety and more specifically of CO2 containment, two of the greatest issues concerns the location of the plume - in comparison with the potential leakage pathways - and the quantity of mobile CO2 in case of unwanted upward migration. The migration of the injected plume has therefore been the subject of numerous studies. All these studies highlight the site- and condition-specificity of the evolution of the trapped plume fraction. Particularly, the structural characteristics of the geological formations, the initial hydrogeological conditions and absolute flow properties of the reservoir, as well as the multiphase flow parameters (relative permeability and capillary pressure) relatively to the CO2/brine system have been shown to influence the pressure evolution and the behaviour of the mobile gaseous plume after the injection. Knowledge of these parameters is often limited especially in the early stages of a storage project (before or in the first years of injection); the assessment of the fate of the injected CO2 is therefore associated to several sources of uncertainties. The improvement of the knowledge on a specific site, before and during the life-time of the storage operations is essential as it may allow a decrease of the uncertainty on the outputs. However, additional data acquisition is likely to be expensive and time consuming, and the parameters to be characterized might be numerous. Thus, under time and budget constraints, ranking the parameters to be estimated according to their impact for the long term assessment of the CO2 fate seems necessary. Such an importance ranking (aka sensitivity analysis) has been advocated by regulators in the European directive on CO2 storage for instance. However, performing such a sensitivity analysis might be challenging in the context of CO2 storage. First, assumptions in the modelling procedure can be strong, because data can be scarce and might not be well-defined on a specific site. This is particularly the case for multiphase flow parameters (relative permeability and capillary pressure including hysteresis effects) curves specific to the CO2/brine system and to the storage conditions; most of the time they do not benefit from previous studies of the site, even in sedimentary basin that are historically well-characterized with regards to intrinsic hydraulic properties. Secondly, a robust sensitivity analysis requires a large amount of simulations, which might not be feasible when using computationally intensive simulations of the CO2 fate on long term at reservoir-scale. Meta-modelling techniques (aka response surface or reduced order models) can be developed to circumvent such a difficulty. In this work, we propose an approach to assess the importance ranking of uncertainty sources, with regards to the long term fate of the mobile CO2 on a specific case, considering notably solution and residual trapping. We consider the case of a large-scale storage site in the Paris basin (France) at the post-screening stage, which is characterized by a relatively high but typical level of uncertainty. In a first step, the data at disposal have been collected and the outcome variables of interest according to our problem selected (in our case, the dissolved CO2, the residual CO2, and the distance of the mobile plume from the injection point over time). A 3D dynamic model has been developed from a geological model of the targeted formation. In a second step, choices in terms of input parameters and associated uncertainty representation have been made. In total, we investigate the sensitivity to seven different input parameters: porosity, permeability, permeability anisotropy, regional hydraulic gradient, relative permeability, capillary pressure and mesh size. According to the different levels of knowledge, the uncertainty on the input parameters have been represented either by a continuous probability distribution (when enough information is available) or by a set of possible scenarios (when little information is available), i.e. by a categorical variables taking on discrete values, each of them assigned to a different scenario. Considering each of the variables of interest, the approach for importance ranking is divided into two steps: 1. qualitative analysis: some reference simulations are precisely studied in the purpose of producing tornado diagrams for a better understanding of input parameters variations qualitative effects; 2. Quantitative analysis: a robust global variance-based sensitivity analysis VBSA relying on the Sobol' indices is chosen and performed. Yet, the implementation of VBSA in our case is hindered by two major limitations. First, VBSA is computationally intensive and requires a large number of model runs, of the order of 10,000, which is impractical using a large-scale flow model with CPU time typically reaching a few hours. The second problem is related to the nature of the model input parameter: several of them are represented by a set of possible scenarios to which a discrete categorical indicator is assigned. To circumvent both limitations, VBSA is combined with ACOSSO-like meta-modelling technique, which can jointly account for continuous variables and categorical variables. This strategy is applied by using 300 large-scale complex dynamic 3D model runs. This procedure gives the temporal evolution of the sensitivity indices assigned to each input parameter considering each variable of interest. Interestingly, porosity, relative permeability and capillary pressure have the main influence but with different magnitude over time and depending on the variable of interest. In summary, the approach, generic and applicable to different uncertain contexts, allows to answer two main issues: 1) the identification of the inputs parameter ranges or scenarios that contribute to a higher safety or contrarily to unwanted situations; 2) the identification of the main sources of variability as well as the parameters with negligible influence and therefore the prioritization of the effort to be made to improve the predictability of the numerical simulations.

Wells drilled through low-permeable caprock are potential connections between the CO2 storage reservoir and overlying sensitive targets like aquifers and targets located at the surface. The wellbore integrity can be compromised due to in situ operations, including drilling, completion, operations and abandonment or to geochemical degradation of the caprock-cement-casing system. We present here an experimental set-up in the underground rock laboratory of Mont-Terri (St Ursanne, canton of Jura, Switzerland): the drilling and well completion in the laboratory will be done in the aim of reconstructing interfaces between the caprock, the cement and the casing steel that would be close to the ones observed in situ. These well features will then be dipped within a CO2 stream, during a given time period before a final over-coring. Such an experiment should provide new insights on the quality of bounding between casing/cement/clay interfaces and its evolution due to geochemical reactions. In parallel, a modeling effort is performed focused on both geochemical and transport aspects of the interactions between the fluids and the well compartments.