No abstract

International audienceGeochemistry plays an important role when assessing the impact of CO2 storage. Due to the potential corrosive character of CO2, it might affect the chemical and physical properties of the wells, the reservoir and its surroundings and increase the environmental and financial risk of CO2 storage projects in deep geological structures. An overview of geochemical and solute transport modelling for CO2 storage purposes is given, its data requirements and gaps are highlighted, and its progress over the last 10 years is discussed. Four different application domains are identified: long-term integrity modelling, injectivity modelling, well integrity modelling and experimental modelling and their current state of the art is discussed. One of the major gaps remaining is the lack of basic thermodynamical and kinetic data at relevant temperature and pressure conditions for each of these four application domains. Real challenges are the coupled solute transport and geomechanical modelling, the modelling of impurities in the CO2 stream and pore-scale modelling applications

Carbon Capture and Storage (CCS) is a technique than can potentially limit the accumulation of greenhouse gases in the atmosphere. Well injectivity issues are of importance for CCS because the gas injection rate must be maintained at a high level (a million tonnes of CO 2 per year and per site) during the industrial operation period (30 to 40 years). The risk of altered permeability must therefore be determined in order to guarantee the sustainability and the security of the CO 2 geological storage. Injection of dry gas in deep saline aquifers might lead to near wellbore drying and salt precipitation. The solid salt might then reduce the rock permeability by clogging pores or by pore throat restriction. The objective of this paper is to present new experimental results on the drying of rocks induced by continuous injection of large amount of dry gas (N 2). The main goal of the study was to understand and model the physical processes that govern the decrease in water saturation in reservoir rocks. Two types of sandstone were used to study slow and fast drying rates and capillary effects on drying. The experimental results evince the main physical parameters that control the key mechanisms. In a companion paper in this issue (André et al., 2013), we show that the continuous approach in the context of a compositional two-phase flow model can fairly well predict the saturation evolution in the near wellbore and the alteration in permeability due to salt precipitation.

The injection of CO 2 into geological reservoirs or deep saline aquifers is being studied to control global warming by limiting greenhouse gas emissions. CO is captured from exhaust gases in power plants or industrial units and stored in underground geological reservoirs. Return on experience withCO 2 injection in the oil industry clearly shows that injectivity problems can be encountered due to several mechanisms including mineral dissolution/ precipitationand physical alteration due to the complete desaturation of the near-wellbore zone. This study describes numerical modelling that is able to reproduce the experimental results of drying of brine-saturated sandstone cores by gas injection in the laboratory. The evolution of water and gas saturation profiles and the precipitation of salt inside the samples are followed with injection time. Numerical results agree well with experimental observations highlighting the key role played by capillary forces during the desiccation process (see the companion paper; Peysson et al., 2013). A tentative extrapolation of experimental results from laboratory scale to the near-well field scale is proposed. This approach is of major importance because it makes it possible to determine the optimal CO 2 injection flow rate according to both the intrinsic petrophysical properties of the porous medium and initial brine salinities.

No abstract

International audienceGeological sequestration of CO2 offers a promising solution for reducing net emissions of greenhouse gases into the atmosphere. This emerging technology must make it possible to inject CO2 into deep saline aquifers or oil- and gas-depleted reservoirs in the supercritical state (P > 7.4MPa and T > 31.1◦C) to achieve a higher density and therefore occupy less volume underground. Previous experimental and numerical simulations have demonstrated that massive CO2 injection in saline reservoirs causes a major disequilibrium of the physical and geochemical characteristics of the host aquifer. The near-well injection zone seems to constitute an underground hydrogeological system particularly impacted by supercriticalCO2 injection and themost sensitive area, where chemical phenomena (e.g. mineral dissolution/precipitation) can have a major impact on the porosity and permeability. Furthermore, these phenomena are highly sensitive to temperature. This study, based on numerical multi-phase simulations, investigates thermal effects during CO2 injection into a deep carbonate formation. Different thermal processes and their influence on the chemical and mineral reactivity of the saline reservoir are discussed. This study underlines both the minor effects of intrinsic thermal and thermodynamic processes on mineral reactivity in carbonate aquifers, and the influence of anthropic thermal processes (e.g. injection temperature) on the carbonates' behaviou

International audienceThe surface tension of the air/water interface is a phenomenon of particular interest in the water-unsaturated zone of porous media because it influences the contact angle and consequently the capillary water volume. A mechanistic model based on the modified Poisson-Boltzmann equation and the Pitzer theory is described and used to predict, under isothermal and isobaric conditions, the surface tension of 1:1 electrolytes at high salinity. These theories enable the determination of the electrical potential at the air/water interface and the activity coefficient of the ionic species in the bulk pore water, respectively. Hydration free energies of the structure-making and structure-breaking ions that influence the surface tension at high salinity are taken into account. Structure-making ions flee the air/water surface because they can better organize the water dipoles in bulk water than at the interface. Structure-breaking ions are positively adsorbed at the air/water interface because the bulk water can better organize their hydrogen bonding network without these ions. The resulting surface tension increases and decreases, respectively, compared to the surface tension of pure water. The model predictions are in good agreement with the surface tension data for 1:1 electrolytes (NaCl, KCl, HCl, NaNO3, KNO3, HNO3 electrolytes) and the optimized parameters depend on the effective electrostatic diameters of cations and on the hydration free energies of the ions at the interface

International audienceThe thermal and volumetric properties of complex aqueous solutions are described according to the Pitzer equation, explicitly taking into account the speciation in the aqueous solutions. The thermal properties are the apparent relative molar enthalpy (L_ϕ) and the apparent molar heat capacity (C_(p,ϕ)). The volumetric property is the apparent molar volume (V_ϕ). Equations describing these properties are obtained from the temperature or pressure derivatives of the excess Gibbs energy and make it possible to calculate the dilution enthalpy (〖∆H〗_ ^D), the heat capacity (c_p) and the density (ρ) of aqueous solutions up to high concentrations. Their implementation in PHREEQC V.3 (Parkhurst and Appelo, 2013) is described and has led to a new numerical tool, called PhreeSCALE. It was tested first, using a set of parameters (specific interaction parameters and standard properties) from the literature for two binary systems (Na2SO4-H2O and MgSO4-H2O), for the quaternary K-Na-Cl-SO4 system (heat capacity only) and for the Na-K-Ca-Mg-Cl-SO4-HCO3 system (density only). The results obtained with PhreeSCALE are in agreement with the literature data when the same standard solution heat capacity (C_p^0) and volume (V^0) values are used. For further applications of this improved computation tool, these standard solution properties were calculated independently, using the Helgeson-Kirkham-Flowers (HKF) equations. By using this kind of approach, most of the Pitzer interaction parameters coming from literature become obsolete since they are not coherent with the standard properties calculated according to the HKF formalism. Consequently a new set of interaction parameters must be determined. This approach was successfully applied to the Na2SO4-H2O and MgSO4-H2O binary systems, providing a new set of optimized interaction parameters, consistent with the standard solution properties derived from the HKF equations