Native Brine Research Articles

A Review of Coupled Geochemical–Geomechanical Impacts in Subsurface CO2, H2, and Air Storage Systems

Increased demand for decarbonization and renewable energy has led to increasing interest in engineered subsurface storage systems for large-scale carbon reduction and energy storage. In these applications, a working fluid (CO2, H2, air, etc.) is injected into a deep formation for permanent sequestration or seasonal energy storage. The heterogeneous nature of the porous formation and the fluid–rock interactions introduce complexity and uncertainty in the fate of the injected component and host formations in these applications. Interactions between the working gas, native brine, and formation mineralogy must be adequately assessed to evaluate the efficiency, risk, and viability of a particular storage site and operational regime. This study reviews the current state of knowledge about coupled geochemical–geomechanical impacts in geologic carbon sequestration (GCS), underground hydrogen storage (UHS), and compressed air energy storage (CAES) systems involving the injection of CO2, H2, and air. Specific review topics include (1) existing injection induced geochemical reactions in these systems; (2) the impact of these reactions on the porosity and permeability of host formation; (3) the impact of these reactions on the mechanical properties of host formation; and (4) the investigation of geochemical-geomechanical process in pilot scale GCS. This study helps to facilitate an understanding of the potential geochemical–geomechanical risks involved in different subsurface energy storage systems and highlights future research needs.

Liquid-liquid extraction of boron from continental brines by 2-butyl-1-octanol diluted in kerosene.

Lithium production from brines generates significant quantities of salts, including boron, that are not effectively utilized and end up being stored in landfills. This study delves into a novel approach for directly extracting boron from native brines without performing solar evaporation as an alternative to traditional methods based on boron extraction from ores, offering a sustainable route to producing boric acid or borax. By exploring factors such as 2-butyl-1-octanol concentration, phase volume ratio, temperature, and pH, the research scrutinizes boron extraction efficiency from two native brines sourced from the salar de Hombre Muerto in Argentina, alongside a synthetic brine simulating these native compositions. Notably, the extractant demonstrates exceptional promise due to its limited solubility in the brine, measuring at just 18 mg L-1. Optimal conditions-2 mol L-1 2-butyl-1-octanol, O/A ratio of 4, 25 °C temperature, and pH of 5.5-resulted in a remarkable 98.2% and 94.2% recovery of boron from synthetic and native brines, respectively. Importantly, this extraction process showcased minimal co-extraction of lithium, calcium, magnesium, potassium, and sodium. Leveraging these findings, a proposed flowsheet outlines a highly selective method for extracting boron from brines, presenting an alternative avenue to conventional borax production from boron ores.

Comparison of simple and active solar stills for freshwater recovery during lithium brine mining

Lithium mining from brines raise environmental issues due to huge volumes of both saline and freshwater being constantly pumped in desertic environments. Data indicating the slow depletion of both underground water levels and lagoon surfaces in the regions where large lithium brine mining exploitations are located have recently being disclosed. Amongst different direct lithium extraction methodologies, DLE, for more sustainable lithium recovery, a few proposals aim at the recovery of freshwater from the high salinity brines. About 900 kg of freshwater could potentially be recovered per cubic meter of processed native brine. The water evaporation and freshwater production capabilities of a simple and an active solar still are compared in this work. These are two simple and relatively low-cost technologies that could be adapted to existing solar evaporation ponds. The two systems were thermodynamically modelled. Equations were derived which were fed with real meteorological data from the Olaroz salt lake location and brine properties derived from the Pitzer model for the said brine. Analysis of the heat fluxes show that the behavior of both systems is relatively similar with large heat losses that are responsible for neither of the systems reaching the evaporation rate of the evaporation ponds.

Comparative analysis of hydrogen, methane and nitrogen relative permeability: Implications for Underground Hydrogen Storage

Underground Hydrogen Storage (UHS) is an emerging technology which aims to store terawatt-scale energy in the subsurface to alleviate daily and seasonal fluctuations in the ever-increasing renewable energy market. Depleted gas reservoirs and aquifers will be the main targets of storage which requires an understanding of the interaction between formation or cushion gas with native brine. A comprehensive comparison of the petrophysical and two-phase flow properties of the hydrogen-water, methane-water and nitrogen-water systems at in-situ conditions is the focus of our work. We conduct steady-state relative permeability experiments at 2.13 MPa and 298 K using identical capillary numbers of Nc=2.92×10−7 for all three systems. The saturation and in-situ contact angles are determined with segmentation of 3D micro-CT images. The contact angle of each system is almost identical at the irreducible water saturation, Swi, 44°, 46°, 45°, respectively, as is the interfacial tension of 72.0, 71.5 and 71mN/m, respectively. The capillary pressure-saturation relationships for each system have a maximum difference of 3.8 % which leads to approximately equivalent relative permeability in the Bentheimer sandstone core. The end-point relative permeabilities are krg0=0.049, krg0=0.045 and krg0=0.062 at irreducible water saturations of Swi=0.24, Swi=0.25 and Swi=0.23, respectively. All three gases demonstrate equivalent flow properties which indicates that both nitrogen and methane are suitable analogue gases for laboratory multiphase flow experiments and cushion gas to improve safety and the economics of commercial UHS projects. The results enable history matched depleted gas reservoir performance to be used as a guide for UHS.

Effect of [Na+]/[Li+] concentration ratios in brines on lithium carbonate production through membrane electrolysis.

Lithium is a fundamental raw material for the production of rechargeable batteries. The technology currently in use for lithium salts recovery from continental brines entails the evaporation of huge water volumes in desert environments. It also requires that the native brines reside for not less than a year in open air ponds, and is only applicable to selected compositions, not allowing its application to more diluted brines such as those geothermally sourced or waters produced from the oil industry. We have proposed an alternative technology based on membrane electrolysis. In three consecutive water electrolyzers, fitted alternately with anion and cation permselective membranes, we have shown, at proof-of-concept level, that it is possible to sequentially recover lithium carbonate and several by-products, including magnesium and calcium hydroxide, sodium bicarbonate, H2 and HCl. The big challenge is to bring this technology closer to practical implementation. Thus, the issue is how to apply relatively well-known electrochemical technology principles to large volumes and to a highly complex and saline broth. We have studied the application of this new methodology to ternary mixtures (NaCl, LiCl and KCl) with constant LiCl and KCl composition and increasing NaCl content. Results showed very similar behaviour for systems containing [Na+]/[Li+] concentration ratios ranging from 1.24 to 4.80. The voltage developed between the anode and cathode is almost the same in all systems at roughly 3.5 V when a constant current density of 50 A m-2 is applied. The three monovalent cations migrate with different rates across the cation exchange membrane, with Li+ being the most sluggish and thus crystallization of Li2CO3 only occurs close to completion of the electrolysis. The dimensionless concentration profiles are almost indistinguishable despite the changes in total salinity. The solids crystallized from different feeds showed higher Na+ and K+ contents as the initial Na+ concentration was increased. However, solids with over 99.9% purity in Li2CO3 could be obtained after a simple re-suspension treatment in hot water. The electrochemical energy consumption greatly increases with higher Na+ concentrations, and the amount of fresh water that can be recovered is diminished.

Use closed reservoirs for CO2 storage and heat recovery: A two-stage brine-extraction and CO2-circulation strategy

Integrated CO2 (carbon dioxide) geologic storage (CGS) and CO2 plume geothermal (CPG) production provides an attractive approach not only to reduce atmospheric CO2 concentration but also to generate carbon-free geothermal energy to supplement electricity power. The current CGS-CPG studies are mostly limited to large-scale thick saline formations with open boundaries. Small to moderate scale closed-boundary reservoirs, which are typical for oil/gas fields, have rarely been evaluated for CGS-CPG. One of the major reasons is that the closed system has limited storage volume, and native brine has nowhere to escape to free storage space for injected CO2. This study provides a solution to this issue by implementing an innovative two-stage operational strategy to realize CGS-CPG in closed reservoirs. The proposed strategy extracts pure hot brine and CO2 in two sequential stages by two separate wells, and can effectively avoid brine-CO2 separation on ground surface. A suite of numerical models is developed to evaluate the approach with a variety of reservoir conditions and operations. Results demonstrate the feasibility of our solution for implementing CGS-CPG in closed systems, and indicate the tremendous potentials to use depleted oi/gas reservoirs as the candidate fields, which widely exist in North Oman and the world.

Exploring the Impacts of Source Condition Uncertainties on Far‐Field Brine Leakage Plume Predictions in Geologic Storage of CO2: Integrating Intermediate‐Scale Laboratory Testing With Numerical Modeling

AbstractNatural fissures/faults or pressure‐induced fractures in the caprock confining injected CO2 have been identified as a potential leakage pathways of far‐field native brine contaminating underground sources of drinking water. Developing models to simulate brine propagation through the overlaying formations and aquifers is essential to conduct reliable pre‐ and post‐risk assessments for site selection and operation, respectively. One of the primary challenges of performing such simulations is lack of adequate information about source conditions, such as hydro‐structural properties of caprock fracture/fault zone and the permeability field of the storage formation. This research investigates the impact of source condition uncertainties on the accuracy of leaking brine plume predictions. Prediction models should be able to simulate brine leakage and transport in complex multilayered geologic systems with interacting regional natural and leakage flows. As field datasets are not readily available for model testing and validation, three comprehensive intermediate‐scale laboratory experiments were used to generate high‐resolution spatiotemporal data on brine plume development under different leakage scenarios. Experimental data were used to validate a flow and transport model developed using existing code FEFLOW to simulate brine plume under varying source conditions. Spatial moment analysis was conducted to evaluate how uncertainty in source conditions impacts brine migration predictions. Results showed that inaccurately prescribing the permeability field of storage formation and caprock fractures in models can cause errors in leakage pathway and spread predictions up to ∼19% and ∼100%, respectively. These findings will help in selecting and characterizing storage sites by factoring in potential risks to shallow groundwater resources.

Permeability Decline by Clay Fines Migration around a Low-Salinity Fluid Injection Well.

Migration of clay fines can be a concern when less saline fluids are injected into brine-saturated sandstone formations containing clays. If the salinity near fluid injection wells decreases below a critical value, the clay fines near the injection may detach, start migrating, and finally clog the pores. This effect can cause permeability decline near the well and may rapidly reduce the well injectivity. The focus of this work is on evaluating the impacts of clay fines migration on permeability decline in the field, using a numerical model and pressure buildup data collected during successive variable-rate water injections in a deep sandstone reservoir. The numerical model accounts for the mixing of low-salinity water with native brine and the migration of clay fines with the detachment and pore-clogging processes. The model interpretation of the pressure buildup data implies that the observed reduction in well injectivity is mainly associated with the clay fines migration and related pore clogging near the well. The model reasonably well represents the pressure buildup data during the injections. Our simulations demonstrate that the permeability near the well can rapidly decline within the first hour of injection. The measured pressure buildup in post-injection periods appears to decay more rapidly, compared to the simulation results of the model that assume irreversible permeability damage. This raises the question whether the permeability damage may be partly reversible near the well by backflow of brine after the injection of low-salinity water.

Comparative geochemistry of flowback chemistry from the Utica/Point Pleasant and Marcellus formations

Flowback/Produced fluid samples were collected from several wells from two Utica/Point Pleasant (UPP) sites (UPPW and UPPS) in Ohio, and one Marcellus (Marcellus Shale Energy and Environment Laboratory (MSEEL)) site in West Virginia over a period of approximately two years. Although these formations have different ages, depositional environments, diagenetic histories, and geochemical and mineralogical compositions (i.e. the UPP is significantly more carbonate rich than the Marcellus which is more siliceous), analysis of trends in fluid species over time shows that, overall, the TDS and major solubilized elements (Na, Ca, Cl) in the UPP and Marcellus brines are remarkably similar. Total dissolved solutes (TDS) in these brines ranged from approximately 40 to 250 g/L salt, and in general, concentrations increased with time elapsed since natural gas well completion and stimulation. The behavior of Na, Br, and Cl suggests that the produced water signatures from these formations are largely derived from the native formational brines which display evidence of originating from evaporated seawater. There is a strong correlation between Cl and Br, indicating that both species behave conservatively, and the similarity among each of these brines suggests no appreciable contribution of salt from halite dissolution because Br is excluded from the halite structure. Cl/Br ratios in the brines range from ~80 to 120 (mg/L/mg/L). Other elements, such as K, which readily reacts between fluids and ion exchange sites on clays, generally exhibit conservative behavior for an individual site, but show significant variations among each of the different well pads.The concentrations of Sr and Ba vary dramatically among well sites, and increase with respect to Cl− over time, suggesting increasing solubilization, presumably from desorption from clay minerals or dissolution of carbonates or sulfates from the source formation(s). The UPPW well site has very low Ba due to high-sulfate input fluid, which resulted in precipitation of barite/celestite in the brines. In contrast the UPPS well site had elevated Sr (~ 3500 mg/L), presumably due to the use of Sr-rich recycled brine used in hydraulic fracturing. The Marcellus site had the highest Ba concentrations (up to 10 g/L) and highest Ba/Sr ratios in the fluids, due to the high concentration of barium in the Marcellus target (~ 1000 ppm, as compared to ~200 ppm in the UPP). These observations suggest that solutes in the FP fluids are derived from native brines, water-rock interactions that have occurred over geologic time scales, as well as some contribution from contemporaneous reactions in the subsurface. The results also show that the composition of the injected fluid can influence flowback fluid chemistry and possibly production efficiency.

Potential water recovery during lithium mining from high salinity brines

Lithium extraction from continental brines involves the evaporation of large amounts of water in open air ponds, in order to concentrate the brine. The evaporitic technology implies the evaporation of large water volumes, raising environmental concerns. If we envision the use of desalination processes for the concentration of lithium-rich brines, then fresh water production/recovery becomes a process well integrated with lithium extraction. Here we apply the Pitzer thermodynamic model with effective molality to estimate activity coefficients for 8 different native brines, and for the resulting concentrated solutions produced by a hypothetical advanced desalinization technique. In all cases, rational activity coefficients deviate considerably from unity. We calculate next the least work of separation for a hypothetical desalination process for the 8 different brines. Because of the large total salinity, the calculation shows that the least work of separation ranges from 18 until 42 kJ kg−1 at nil recovery ratio, and escalating from those numbers as more water is recovered. We can also predict the boiling point elevation, the vapour pressure lowering, and the osmotic pressure. Our calculations show that results are not strictly proportional to the total dissolved solids. Results are strongly dependent with the specific chemical composition of each brine, with the amount of divalent ions (Mg-Ca-SO42−) in particular strongly influencing calculations. Fresh water and lithium minerals production could be part of a single integrated production system.

An experimental study of density-driven convection of fluid pairs with viscosity contrast in porous media

CO2 dissolution in saline water during aquifer sequestration causes natural convection because of the density difference between CO2-saturated brine and native brine. In this study, the convective fingers behavior during convection in porous media was visualized by magnetic resonance imaging (MRI). Four kinds of miscible fluid pairs were used as the equivalents of CO2-saturated brine and native brine. Images of finger development were obtained. There are two types of convective fingers that form vertically symmetrical shapes: downward fingers of the dense fluid and upward fingers of the light fluid. The typical stages of natural convection, finger appearance, finger propagation, new finger generation, and finger coalescence were observed in this study. We analyzed the effects of viscosity contrast variation on convective onset. It was found that the viscosity contrast affects not only the convection time but also the finger growth velocity. The dimensionless mass transfer coefficient is characterized by the Sherwood number. The Sherwood number has a power law relationship with the Rayleigh number, with the exponent being larger than 1 for fluid pairs with apparent viscosity contrast. Experimental results showed that a higher viscosity contrast of the fluid pair causes a viscosity increase in the transition zone, resulting in lower mobility of the fluids and retarding convective mixing. For fluid pairs with similar densities, a high viscosity contrast is not conducive to efficient mass transfer in the density-driven convection process.

Impacts on mechanical strength of chemical reactions induced by hydrous supercritical CO2 in Boise Sandstone

Geomechanics experiments were used to assess mechanical alteration of Boise Sandstone promoted by reactions with supercritical carbon dioxide (scCO2) and water vapor. During geologic carbon storage, scCO2 is injected into subsurface reservoirs, forming buoyant plumes. At brine-plume interfaces, scCO2 can dissolve into native brines, and water from brines can partition into scCO2, forming hydrous scCO2. This study investigates the effect of hydrous scCO2 on the strength of Boise Sandstone. Samples are first exposed to recirculating hydrous scCO2 for 24 h at 70 °C and 13.8 MPa scCO2 pressure. Samples are reacted with scCO2 with added water contents up to 500 mL. After scCO2 exposure, samples are deformed at room temperature under confining pressures of 3.4, 6.9, and 10.3 MPa. The results demonstrate that hydrous scCO2 induces chemical reactions in Boise Sandstone, with ions migrating from the solid into the hydrous scCO2 phase. At the longer time-scales, these reactions could lead to mechanical weakening in the samples; however, on the scale of our experiments, the strength changes are within sample variability. Because the solubility of water in scCO2 is extremely low (0.008 mol H2O per 1 mol CO2), the mineral dissolution of Boise Sandstone was under 0.002 wt.%. Additionally, mineral grains and pore throats in Boise Sandstone are cemented with quartz, which is not susceptible to dissolution at these conditions. Our results indicate that humidity in scCO2 plumes is unlikely to sustain chemical reactions and induce long term strength changes in quartz cemented sandstones due to resistant mineralogies and low water solubility.

Estimation of reduced pressure buildup due to brine seepage using a convolution technique

CO2 sequestration involves injection of large volumes of CO2 into a storage reservoir bounded above and below by low-permeability seals. Although capillary effects are usually sufficient to prevent CO2 leakage through the caprock, the native brine will slowly migrate through the over- and underlying units when subject to overpressure in the reservoir. At large scales and over long time periods, diffuse fluid migration may have an important impact on large-scale pressure development. Typically, simulation studies of CO2 injection often omit the possibility of brine migration through the top and bottom boundaries of the reservoir. One reason is that vertical fluid flow requires additional resolution outside of the storage reservoir that poses a large computational burden. Therefore, analytical methods are an attractive approach for capturing diffuse brine leakage. In low-permeability layers, the flow is predominantly vertical, and the local system can be reduced to a 1D (vertical) equation. This can be solved on a semi-infinite (vertical) domain for a thick seal (> 10 − 20m), with the reservoir overpressure applied as a boundary condition. Because the boundary condition is not constant in time, the resulting solution is a convolution integral that must be computed at regular time intervals. In this paper, we couple the analytical solution for vertical brine leakage with a vertical equilibrium simulator (VESA). The VESA simulator is a reduced-dimension (2D) numerical model for two-phase flow in gravity-segregated systems, which is an appropriate assumption for large-scale CO2 storage. Coupling analytical solution for brine migration into a numerical simulator gives greater flexibility modeling injection into heterogeneous reservoirs. We find that the additional computational burden of the convolution integral is minimal compared to solving the full 3D system at the correct resolution. A solution for pressure development in the adjacent strata is also obtained analytically, leading to a fully 3D representation of pressure in the system. The coupled code is benchmarked with a fully analytical solution, and then applied to large-scale CO2 injection into the Utsira formation. We study the impact of diffuse brine leakage on development of large-scale overpressure in the storage reservoir for scenarios of high-volume CO2 injection.

Predator-prey interactions between native brine shrimp Artemia parthenogenetica and the alien boatman Trichocorixa verticalis: influence of salinity, predator sex, and size, abundance and parasitic status of prey.

Trichocorixa verticalis (T. verticalis), native to North America and the Caribbean islands, is an invasive waterboatman species (Corixidae) in the southwest of the Iberian Peninsula. Previous studies in the native range have suggested that predation by T. verticalis can regulate the abundance of Anostracan and Cladoceran zooplankton in saline ecosystems, causing increases in phytoplankton through a trophic cascade. In this experimental study, we tested the predator–prey relationship between the native brine shrimp Artemia parthenogenetica, and T. verticalis from the Odiel salt ponds in SW Spain. In three experiments, we investigated (1) the effects of Artemia life stage (metanauplii, juveniles, and adults), (2) abundance (three, six, and 12 adult Artemia) and (3) parasitic status (Artemia infected with avian cestodes or uninfected) on predation rates by T. verticalis. We also considered how predation rates in all three experiments were influenced by the sex of T. verticalis and by different salinities (25 and 55 g l−1). Experiment 1 showed that predation rates were highest for metanauplii, possibly because their photophilic behavior makes them more prone to predation. In Experiment 2, we found that predation rate was higher for female T. verticalis and the higher salinity, although the strength of the sex effect varied between treatments. Experiment 3 showed that T. verticalis selectively predated adult Artemia infected with cestodes (red in color), as previously reported for predation by avian final hosts. Collectively, these results indicate that T. verticalis are important predators in their introduced range, and are likely to reduce the abundance of Artemia in more salt ponds as they expand their range, thus increasing phytoplankton abundance through trophic cascades.

Post-injection trapping of mobile CO 2 in deep aquifers: Assessing the importance of model and parameter uncertainties

Predicting the fate of the injected CO2 is crucial for the safety of carbon storage operations in deep saline aquifers: especially the evolution of the position, the spreading and the quantity of the mobile CO2 plume during and after the injection has to be understood to prevent any loss of containment. Fluid flow modelling is challenging not only given the uncertainties on subsurface formation intrinsic properties (parameter uncertainty) but also on the modelling choices/assumptions for representing and numerically implementing the processes occurring when CO2 displaces the native brine (model uncertainty). Sensitivity analysis is needed to identify the group of factors which contributes the most to the uncertainties in the predictions. In this paper, we present an approach for assessing the importance of model and parameter uncertainties regarding post-injection trapping of mobile CO2. This approach includes the representation of input parameters, the choice of relevant simulation outputs, the assessment of the mobile plume evolution with a flow simulator and the importance ranking for input parameters. A variance-based sensitivity analysis is proposed, associated with the ACOSSO-like meta-modelling technique to tackle the issues linked with the computational burden posed by the use of long-running simulations and with the different types of uncertainties to be accounted for (model and parameter). The approach is tested on a potential site for CO2 storage in the Paris basin (France) representative of a project in preliminary stage of development. The approach provides physically sound outcomes despite the challenging context of the case study. In addition, these outcomes appear very helpful for prioritizing the future characterisation efforts and monitoring requirements, and for simplifying the modelling exercise.

Oil removal and effects of spilled oil on active microbial communities in close to salt-saturation brines

Abiotic and biotic processes associated with the degradation of a light petroleum in brines close to the salt-saturation (~31%) and the effect of labile organic matter (LOM) supply (casaminoacids/citrate; 0.2 and 0.1% w/v, respectively) were followed during an incubation of 30days. After 4-week incubation at 40°C under light/dark cycles, a 24% of abiotic degradation was observed in untreated brines. The stimulation of native brines community with LOM addition allowed an additional 12.8% oil attenuation due to biodegradation processes. Successional changes in the active microbial community structure due to the oil contamination (16S rRNA DGGE approach) showed the selection of one phylotype affiliated to Salinibacter and the disappearance of Haloquadratum walsbyi in untreated brines. In LOM-amended microcosms, phylotypes related to Salinibacter, Haloarcula, Haloterrigena and Halorhabdus were selected. An effect of hydrocarbon contamination was only observed in the bacterial community with the inhibition of two dominant proteobacterial phylotypes. This study further confirms that short-term and moderate oil biodegradation is possible in LOM-stimulated brines. Biodegradation should be much more reduced under in situ conditions. Self-cleaning capacities of close to saturation hypersaline lakes appears, therefore very limited compared to non-extreme haline environments.

Major geochemical characteristics of geothermal brines from the Upper Rhine Graben granitic basement with constraints on temperature and circulation

This paper is the first to present the main geochemical characteristics of the native brines collected from all the geothermal wells penetrating the granite basement underlying the sedimentary cover, in the Upper Rhine Graben. These deep wells (from 2580 to 5000m) were only drilled in four geothermal sites (Soultz-sous-Forêts and Rittershoffen in France; Landau and Insheim in Germany). The Na–Cl geothermal brine samples collected from the granite returned TDS values ranging from 99 to 107g/l with pH values close to 5, along with Cl and Br concentrations and δD, δ18O and δ34S values that indicate a multiple origin with mixing between primary brine formed by advanced evaporation of seawater (probably until the stage of halite precipitation) and dilute meteoric water, plus contributions from halite dissolution following successive marine transgression-regression cycles from the Triassic to the Oligocene. Chemical, isotopic and gas geothermometers indicate concordant reservoir temperatures close to 225±25°C for all the fluids, even though the maximum temperature so far measured on site is 200°C. An exhaustive literature review has indicated that only the geothermal brine from the deep Cronenbourg well (2870m) ending in the Buntsandstein has similar chemical and isotopic compositions (apart from Br and Ca) to the fluids from the granite, with an identical estimation of reservoir temperature from geothermometry. Geothermal brine from the deep Bruchsal well (2540m), drilled down to the junction of the Buntsandstein and the Saxo-Thuringian formations, has a higher TDS value (120–125g/l) with its chemical and isotopic compositions giving a lower estimation of reservoir temperature (190±25°C). By contrast, geothermal brine from the Bühl well (2655m) ending in the Buntsandstein has an even higher TDS value of about 201g/l and a lower temperature-at-depth estimation of 110±25°C, close to the temperature measured on site (115°C). The above results indicate that the geothermal fluids collected from the granite probably originate from Triassic sedimentary formations located at great depth (≥4km) with temperatures close to 225±25°C in the centre of the Rhine Graben, but that their different TDS and Cl/Br values reflect the presence of several distinct geothermal reservoirs. Many discrepancies due to high-temperature water-rock interactions are revealed on comparing the chemical and isotopic compositions of the hot brines with those of cooler brines from Bühl and the Landau Eocene–Oligocene oilfield wells, among others. The hottest brines are much enriched in K, Ca, SiO2, Li, Rb, Cs, As, Sr, Ba, Mn, Nd, U and in metals such as Zn, Pb, Cu, Co, Cd, Sb, but are depleted mainly in Mg, SO4 and B and have much lower isotopic Li and B signatures. The He isotopic signatures of the gases associated with these fluids (R/Ratm. = 0.128 at Bruchsal and 0.252 at Insheim) confirm that the thermal anomalies are mainly crustal and not mantle-derived (1.46% and 2.88% of mantellic He, respectively, for the two sites). Thus it is concluded that the thermal anomalies are associated mainly with the convective circulation of hot fluids along probable NE–SW faults between the graben's deep sedimentary centre and the fractured granite basement at its edges. Moreover, the western part of the Upper Rhine Graben (the Landau, Insheim, Soultz, Rittershoffen and Cronenbourg sites) seems to be hotter than the eastern part (Bruchsal and Bühl). According to the U-Th isotope system, the minimum transit time of these deep geothermal brines would be about 1000years.

Analysis of a time dependent injection strategy to accelerate the residual trapping of sequestered CO2 in the geologic subsurface

A time dependent injection strategy for greatly accelerating the immobilization of geologically sequestered CO2 is proposed and analyzed. The injection of high density CO2 into a brine aquifer is followed by brine flooding facilitating residual trapping and dissolution of the CO2 on time scales much shorter than those that would occur by natural processes. One-dimensional kinematic wave equations are derived for the two-phase flow of brine and CO2 and for the transport of dissolved CO2. A solution of these equations using the method of characteristics reveals that brine flooding is most effective when the kinematic wave speed of CO2 saturation is higher than the propagation velocity of a shock wave separating the two-phase flow from the native brine. Finite volume simulation using the reservoir simulator TOUGH2 with PetraSIM interface are generally in good agreement with the one-dimensional model, but show that gravitational overriding of the CO2 can become important if the duration of the injection process is too long. Both methods show that brine flooding is able to reduce the mass fraction of mobile CO2 to less than 10% using a volume ratio brine:CO2 of less than 2.75 on time scales comparable to that of the CO2 injection.

Comparing cestode infections and their consequences for host fitness in two sexual branchiopods: alien Artemia franciscana and native A. salina from syntopic-populations.

The American brine shrimp Artemia franciscana is invasive in the Mediterranean region where it has displaced native species (the sexual A. salina, and the clonal A. parthenogenetica) from many salt pond complexes. Artemia populations are parasitized by numerous avian cestodes whose effects have been studied in native species. We present a study from the Ebro Delta salterns (NE Spain), in a salt pond where both A. franciscana and native A. salina populations coexist, providing a unique opportunity to compare the parasite loads of the two sexual species in syntopy. The native species had consistently higher infection parameters, largely because the dominant cestode in A. salina adults and juveniles (Flamingolepis liguloides) was much rarer in A. franciscana. The most abundant cestodes in the alien species were Eurycestus avoceti (in adults) and Flamingolepis flamingo (in juveniles). The abundance of E. avoceti and F. liguloides was higher in the A. franciscana population syntopic with A. salina than in a population sampled at the same time in another pond where the native brine shrimp was absent, possibly because the native shrimp provides a better reservoir for parasite circulation. Infection by cestodes caused red colouration in adult and juvenile A. salina, and also led to castration in a high proportion of adult females. Both these effects were significantly stronger in the native host than in A. franciscana with the same parasite loads. However, for the first time, significant castration effects (for E. avoceti and F. liguloides) and colour change (for six cestode species) were observed in infected A. franciscana. Avian cestodes are likely to help A. franciscana outcompete native species. At the same time, they are likely to reduce the production of A. franciscana cysts in areas where they are harvested commercially.

Flow Dynamics of $$\hbox {CO}_{2}$$ CO 2 /brine at the Interface Between the Storage Formation and Sealing Units in a Multi-layered Model

Pressure distribution and \(\hbox {CO}_{2}\) plume migration are two major interests in \(\hbox {CO}_{2}\) geologic storage as they determine the injectivity and storage capacity. In this study, we adopted a three-layer model comprising a storage formation and the over- and underlying seals and determined three distinct flow regions based on the vertical flux exchange of \(\hbox {CO}_{2}\) and native brine. Regions 1 and 2 showed \(\hbox {CO}_{2}\) flowing from the storage formation to adjacent seals with counter-flowing brine. The characteristics of these fluxes in Region 1 were governed by permeability change due to salt precipitation whereas buoyancy force controlled the flux pattern in Region 2. Region 3 showed brine flowing from storage formation toward the over- and underlying seals, which enabled the displaced brine to escape from the storage formation and make room for \(\hbox {CO}_{2}\) to store as well as reduce the pressure build-up. In the multi-layered model, the counter-flowing brine in flow Region 1 resulted in localized salt precipitation at the upper and lower boundary of storage formation. We assessed the bottom-hole pressure and \(\hbox {CO}_{2}\) mass in caprock with respect to reservoir size. While the formation thickness influenced the bottom-hole pressure in the early stage of injection, the horizontal extension of the reservoir was more influential to pressure build-up during the injection period, and to the stabilized pressure during the post-injection period. The \(\hbox {CO}_{2}\) mass in caprock gently increased during the injection period as well as during the post-injection period and reached about 4–5 % of injected \(\hbox {CO}_{2}\). The percentage of escaped brine from the storage formation ranged from 80–100 % of the \(\hbox {CO}_{2}\) mass stored in the storage formation depending on the reservoir scale.