Effect of injected CO2 on geochemical alteration of the Altmark gas reservoir in Germany

Capturing CO₂ from point sources and storing it in geologic formations is a potential option for allaying the CO₂ level in the atmosphere. In order to evaluate the effect of geological storage of CO₂ on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under in situ conditions of 125 °C and 50 bar CO₂ partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in (a) CO₂ saturated and (b) CO₂ free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the “CO₂ free” environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO₂. In addition, the presence of CO₂ enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids’ concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO₂, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO₂ on long-term geochemical alteration at reservoir scale.     

The impact of diagenetic fluid–rock reactions on Rotliegend sandstone composition and petrophysical properties (Altmark area, central Germany)

In the framework of the German R&D joint project CLEAN (CO₂ large-scale enhanced gas recovery in the Altmark natural gas field), Rotliegend reservoir sandstones of the Altensalzwedel block in the Altmark area (Saxony-Anhalt, central Germany) have been studied to characterise litho- and diagenetic facies, mineral content, geochemical composition, and petrophysical properties. These sands have been deposited in a playa environment dominated by aeolian dunes, dry to wet sand flats and fluvial channel fills. The sediments exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. In sandstones of the damp to wet sandflats, their pristine red colours are preserved and porosity and permeability are only low. Rocks of the aeolian environment and most of the channel fill deposits are preferentially bleached and exhibit moderate to high porosity and permeability. Although geochemical element whole rock content in these rocks is very similar, element correlations are different. Variations in porosity and permeability are mainly due to calcite and anhydrite dissolution and differences in clay coatings with Fe-bearing illitic-chloritic composition exposed to the pore space. Moreover, mineral dissolution patterns as well as compositions (of clays and carbonate) and morphotypes of authigenic minerals (chlorite, illite) are different in red and bleached rocks. Comparison of the geochemical composition and mineralogical features of diagenetically altered sandstones and samples exposed to CO₂-bearing fluids in laboratory batch experiments exhibit similar character. Experiments prove an increase in wettability and water binding capacity during CO₂ impact.     

Reactivity of sandstone and siltstone samples from the Ketzin pilot CO2 storage site-Laboratory experiments and reactive geochemical modeling

To evaluate mineralogical-geochemical changes within the reservoir of the Ketzin pilot CO₂ storage site in Brandenburg, Germany, two sets of laboratory experiments on sandstone and siltstone samples from the Stuttgart Formation have been performed. Samples were exposed to synthetic brine and pure CO₂ at experimental conditions and run durations of 5.5 MPa/40 °C/40 months for sandstone and 7.5 MPa/40 °C/6 months for siltstone samples, respectively. Mineralogical changes in both sets of experiments are generally minor making it difficult to differentiate natural variability of the whole rock samples from CO₂-induced alterations. Results of sandstone experiments suggest dissolution of the anorthite component of plagioclase, anhydrite, K-feldspar, analcime, hematite and chlorite + biotite. Dissolution of the anorthite component of plagioclase, anhydrite and K-feldspars is also observed in siltstone experiments. In an inverse modeling approach, an extensive set of equilibrium simulations was set up in order to reproduce the experimental observations of the sandstone experiments. Simulations generally show fairly good matches with the experimental observations. Best matches with measured brine data are obtained from mineral combinations of albite, analcime, anhydrite, dolomite, hematite, illite, and kaolinite. The major discrepancies during equilibrium modeling, however, are reactions involving Fe²⁺ and Al³⁺. The best matching subsets of the equilibrium models were finally run including kinetic rate laws. These simulations reveal that experimentally determined brine data was well matched, but reactions involving K⁺ and Fe²⁺ are not fully covered. The modeling results identified key primary minerals as well as key chemical processes, but also showed that the models are not capable of covering all possible contingencies.     

Chemical effects of sulfur dioxide co-injection with carbon dioxide on the reservoir and caprock mineralogy and permeability in depleted gas fields

The most suitable candidates for subsurface storage of CO₂ are depleted gas fields. Their ability to retain CO₂ can however be influenced by the effect which impurities in the CO₂ stream (e.g. H₂S and SO₂) have on the mineralogy of reservoir and seal. In order to investigate the effects of SO₂ we carried out laboratory experiments on reservoir and cap rock core samples from gas fields in the northeast of the Netherlands. The rock samples were contained in reactor vessels for 30 days in contact with CO₂ and 100 ppm SO₂ under in-situ conditions (300 bar, 100 °C). The vessels also contained brine with the same composition as in the actual reservoir. Furthermore equilibrium modeling was carried out using PHREEQC software in order to model the experiments on caprock samples.After the experiments the permeability of the reservoir samples had increased by a factor of 1.2–2.2 as a result of dissolution of primary reservoir minerals. Analysis of the associated brine samples before and after the experiments showed that concentrations of K, Si and Al had increased, indicative of silicate mineral dissolution.In the caprock samples, composed of carbonate and anhydrite minerals, permeability changed by a factor of 0.79–23. The increase in permeability is proportional to the amount of carbonate in the caprock. With higher carbonate content in comparison with anhydrite the permeability increase is higher due to the additional carbonate dissolution. This dependency of permeability variations was verified by the modeling study. Hence, caprock with a higher anhydrite content in comparison with carbonate minerals has a lower risk of leakage after co-injection of 100 ppmv SO₂ with CO₂.     

Caprock interaction with CO2: A laboratory study of reactivity of shale with supercritical CO2 and brine

Crushed rock from two caprock samples, a carbonate-rich shale and a clay-rich shale, were reacted with a mixture of brine and supercritical CO₂ (CO₂–brine) in a laboratory batch reactor, at different temperature and pressure conditions. The samples were cored from a proposed underground CO₂ storage site near the town of Longyearbyen in Svalbard. The reacting fluid was a mixture of 1 M NaCl solution and CO₂ (110 bar) and the water/rock ratio was 20:1. Carbon dioxide was injected into the reactors after the solution had been bubbled with N₂, in order to mimic O₂-depleted natural storage conditions. A control reaction was also run on the clay-rich shale sample, where the crushed rock was reacted with brine (CO₂-free brine) at the same experimental conditions. A total of 8 batch reaction experiments were run at temperatures ranging from 80 to 250 °C and total pressures of 110 bar (∼40 bar for the control experiment). The experiments lasted 1–5 weeks.Fluid analysis showed that the aqueous concentration of major elements (i.e. Ca, Mg, Fe, K, Al) and SiO₂ increased in all experiments. Release rates of Fe and SiO₂ were more pronounced in solutions reacted with CO₂–brine as compared to those reacted with CO₂-free brine. For samples reacted with the CO₂–brine, lower temperature reactions (80 °C) released much more Fe and SiO₂ than higher temperature reactions (150–250 °C). Analysis by SEM and XRD of reacted solids also revealed changes in mineralogical compositions. The carbonate-rich shale was more reactive at 250 °C, as revealed by the dissolution of plagioclase and clay minerals (illite and chlorite), dissolution and re-precipitation of carbonates, and the formation of smectite. Carbon dioxide was also permanently sequestered as calcite in the same sample. The clay-rich shale reacted with CO₂–brine did not show major mineralogical alteration. However, a significant amount of analcime was formed in the clay-rich shale reacted with CO₂-free brine; while no trace of analcime was observed in either of the samples reacted with CO₂–brine.     

Dissolution kinetics of selected natural minerals relevant to potential CO2-injection sites – Part 2: Dissolution and alteration of carbonates and feldspars in CO2-bearing brines

Chemical interaction processes among injected CO₂, saline fluids and potential reservoir materials are experimentally simulated to derive dissolution rates of natural materials (minerals) that can be used as input parameters for modeling of CO₂ storage in deep saline formations and risk analyses. In order to study dissolution processes, mineral aliquots were exposed to CO₂-bearing brines at elevated temperature (60, 100, 150 °C) and pressure (85 bar) and at various run durations. Several potential reservoir rocks include carbonates as cement. Calcite and dolomite grains were therefore mainly used as solid starting material. Experiments with the two feldspar varieties alkali feldspar and almost pure anorthite were performed in addition. Grain sizes of the mineral starting materials varied between <63 μm and 500 μm with most experiments performed at grain size fractions of 160 – 250 μm and 250 – 500 μm. All experiments run with a complex synthetic brine (total dissolved solids: ∼156 g/l) according to a natural upper cretaceous formation water. Dry ice was used as CO₂-source. All experiments were done in closed batch reactors. These reactors allow mimicking reservoir conditions far from the injection site as well as reservoir conditions after finishing the CO₂ injection. The concentration changes during the experiment were monitored by ICP-OES measurements of the initial and the post-run fluids. Dissolution rates were derived based on the concentration changes of the brine.Most of the studied experimental variables and parameters (temperature, run duration, grain size, brine composition – expressed as pH-value and ionic strength) impact alteration of the reacting agents, i.e. they change the chemical composition of the brine, change the surfaces of the mineral aliquots exposed to the CO₂-bearing brine, and induce formation of secondary minerals. Hence, all influencing parameters on dissolution processes have to be considered and time-resolved changes of the dissolution behavior have to be implemented in numerical simulations of processes at CO₂ injection sites and CO₂ storage reservoirs.     

Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.     

Experimental study on water–rock interactions during CO2 flooding in the Tensleep Formation,Wyoming, USA

The conditions for mineral alteration and formation damage during CO₂ treatment of Tensleep sandstone reservoirs in northern Wyoming, USA, were examined through core-flooding laboratory experiments carried out under simulated reservoir conditions (80°C and 166 bars). Subsurface cores from the Tensleep sandstone, which were cemented by dolomite and anhydrite, and synthetic brines were used. The brines used were (Ca, Mg, Na)SO₄–NaCl solution (9.69 g/l total dissolved solids) for Run 1 and a 0.25 mol/l NaCl solution for Run 2. The solution used in Run 1 was saturated with respect to anhydrite at run conditions, which is characteristic of Tensleep Formation waters.Three major reactions took place during flooding, including (1) dissolution of dolomite, (2) alteration of K-feldspar to form kaolinite, and (3) precipitation (in Run 1) or dissolution (in Run 2) of anhydrite. All sample solutions remained undersaturated with respect to carbonates. The permeability of all the cores (except one used in Run 2) decreased during the experiments despite the dissolution of authigenic cement. Kaolinite crystal growth occurring in pore throats likely reduced the permeability.Application of the experimental results to reservoirs in the Tensleep Formation indicates that an injection solution will obtain saturation with respect to dolomite (and anhydrite) in the immediate vicinity of the injection well. The injection of NaCl-type water, which can be obtained from other formations, causes a greater increase in porosity than the injection of Tensleep Formation waters because of the dissolution of both dolomite and anhydrite cements.     

Analyses of pre-injection reservoir data for stable carbon isotope trend predictions in CO2 monitoring: preparing for CO2 injection

Baseline monitoring at the proposed enhanced gas recovery site in Altmark (Germany) was carried out in combination with theoretical and laboratory investigations to describe and predict the principles of expected stable carbon isotope and dissolved inorganic carbon (DIC) trends during CO₂ injection in reservoirs. This provides fundamental data for site-specific characterisation for monitoring purposes. Baseline ??¹³C values at the Altmark site ranged between ?1.8 and ?11.5??? and DIC values were about 2?mmol?L^?1. These baseline values form the basis for a theoretical study on the influences of the ambient reservoir conditions on the state of geochemical and isotope equilibrium of the reservoir fluids. Transferring this theoretical study to the Altmark site enables predictions on geochemical trends during potential injection. Assuming that CO₂ would be injected at the Altmark site to pCO₂?=?100?bar and with a ??¹³C of ?30???, at isotopic and geochemical equilibrium, ??¹³C_DIC values would approach this end-member, and DIC concentrations of 1,000?mmol L^?1 would be expected. Laboratory experiments were conducted at low pCO₂ levels (4?C35?bars) to mimic the approach of a CO₂ plume at a monitoring well. These results support field investigations from other sites: that ??¹³C_DIC is a sensitive tool for monitoring CO₂ migration in the subsurface and simultaneously allows quantification of geochemical trapping of CO₂.     

Geochemical controls on a calcite precipitating spring

A small spring fed stream was found to precipitate calcite by mainly inorganic processes and in a nonuniform manner. The spring water originated by rainwater falling in a 0.8 km² basin, infiltrating, and dissolving calcite and dolomite followed by dissolution of gypsum or anhydrite. The Ca²⁺/Mg²⁺ indicates that calcite is probably precipitated in the subsurface from a supersaturated solution. This water emerges from the spring still about 5 times supersaturated with respect to calcite and continues calcite precipitation. When 10 times supersaturation is reached, due to CO₂ degassing the precipitation is more rapid. The calcite accumulation from the stream with a flow of 5 l/s is calculated to be 12600 kg/yr with the highest rates in areas where CO₂ degassing is the greatest. The non-equilibrium, as shown by the high calcite supersaturation, is also reflected in a variable partitioning pattern for Sr²⁺ between the water and calcite.     

On the interaction of pure and impure supercritical CO2 with rock forming minerals in saline aquifers: An experimental geochemical approach

The aim of this experimental study was to evaluate and compare the geochemical impact of pure and impure CO₂ on rock forming minerals of possible CO₂ storage reservoirs. This geochemical approach takes into account the incomplete purification of industrial captured CO₂ and the related effects during injection, and provides relevant data for long-term storage simulations of this specific greenhouse gas. Batch experiments were conducted to investigate the interactions of supercritical CO₂, brine and rock-forming mineral concentrates (albite, microcline, kaolinite, biotite, muscovite, calcite, dolomite and anhydrite) using a newly developed experimental setup. After up to 42 day (1000 h) experiments using pure and impure supercritical CO₂ the dissolution and solution characteristics were examined by XRD, XRF, SEM and EDS for the solid, and ICP–MS and IC for the fluid reactants, respectively. Experiments with mixtures of supercritical CO₂ (99.5 vol.%) and SO₂ or NO₂ impurities (0.5 vol.%) suggest the formation of H₂SO₄ and HNO₃, reflected in pH values between 1 and 4 for experiments with silicates and anhydrite and between 5 and 6 for experiments with carbonates. These acids should be responsible for the general larger amount of cations dissolved from the mineral phases compared to experiments using pure CO₂. For pure CO₂ a pH of around 4 was obtained using silicates and anhydrite, and 7–8 for carbonates. Dissolution of carbonates was observed after both pure and impure CO₂ experiments. Anhydrite was corroded by approximately 50 wt.% and gypsum precipitated during experiments with supercritical CO₂ + NO₂. Silicates do not exhibit visible alterations during all experiments but released an increasing amount of cations in the reaction fluid during experiments with impure CO₂. Nonetheless, precipitated secondary carbonates could not be identified.     

Mineralogical controls on porosity and water chemistry during O2-SO2-CO2 reaction of CO2 storage reservoir and cap-rock core

Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO₂ storage have been characterized and reacted at reservoir conditions with an impure CO₂ stream and low salinity brine. Cores from a target CO₂ storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO₂-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO₂-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO₂ migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks could be expected to act as baffles to fluids preventing vertical fluid migration. Concentrations of dissolved elements including Ca, Fe, Mn, and Ni increased during reactions of several core samples, with Mn, Mg, Co, and Zn correlated with Ca from cap-rock cores. Precipitation of gypsum, Fe-oxides and clays on seal core samples sequestered dissolved elements including Fe through co-precipitation or adsorption. A conceptual model of impure CO₂-water-rock interactions for a siliciclastic reservoir is discussed.     

Solubility of carbon dioxide in aqueous fluids and mineral suspensions at 294 K and subcritical pressures

An experimental investigation has been carried on the solubility of CO₂ in water and 1 M NaCl between 0.3 and 4 MPa, in order to test the validity of the results given by various modelling codes. In addition to experiments with pure fluids, the effect of a range of likely reservoir minerals on CO₂–water interactions, including K-feldspar, kaolinite, calcite, Ca-montmorillonite and Na-montmorillonite were also investigated. In addition to measurements of CO₂ solubility, the pH of the CO₂-saturated suspensions was also measured directly at pressures of up to 1 MPa. The results demonstrate that predictions of CO₂ solubility made with PHREEQC and Geochemist’s Workbench agree to within 20% with the experimental value, provided corrections are first made off-line for the fugacity coefficient of CO₂, while predictions from standalone models are slightly more accurate. In the presence of mineral suspensions, PHREEQC and Geochemist’s Workbench give good results for calcite and kaolinite but underestimate the pH of montmorillonite-bearing assemblages while slightly overestimating the pH of K-feldspar suspensions. These results are significant because they indicate that CO₂-charged fluids reacted with clays may be less acidic than indicated by the models, which will impact predictions of the potential for dissolution of reservoir and cap rock minerals, as well as the potential for leaching of toxic metals.     

Metal release from dolomites at high partial-pressures of CO2

The potential for metal release associated with CO₂ leakage from underground storage formations into shallow aquifers is an important consideration in assessment of risk associated with CO₂ sequestration. Metal release can be driven by acidification of groundwaters caused by dissolution of CO₂ and subsequent dissociation of carbonic acid. Thus, acidity is considered one of the main drivers for water quality degradation when evaluating potential impacts of CO₂ leakage. Dissolution of carbonate minerals buffers the increased acidity. Thus, it is generally thought that carbonate aquifers will be less impacted by CO₂ leakage than non-carbonate aquifers due to their high buffering potential. However, dissolution of carbonate minerals can also release trace metals, often present as impurities in the carbonate crystal structure, into solution. The impact of the release of trace metals through this mechanism on water quality remains relatively unknown. In a previous study we demonstrated that calcite dissolution contributed more metal release into solution than sulfide dissolution or desorption when limestone samples were dissolved in elevated CO₂ conditions. The study presented in this paper expanded our work to dolomite formations and details a thorough investigation on the role of mineral composition and mechanisms on trace element release in the presence of CO₂. Detailed characterization of samples from dolomite formations demonstrated stronger associations of metal releases with dissolution of carbonate mineral phases relative to sulfide minerals or surface sorption sites. Aqueous concentrations of Sr²⁺, CO²⁺, Mn²⁺, Ni²⁺, Tl⁺, and Zn²⁺ increased when these dolomite rocks were exposed to elevated concentrations of CO₂. The aqueous concentrations of these metals correlate to aqueous concentrations of Ca²⁺ throughout the experiments. All of the experimental evidence points to carbonate minerals as the dominant source of metals from these dolomite rocks to solution under experimental CO₂ leakage conditions. Aqueous concentrations of Ca²⁺ and Mg²⁺ predicted from numerical simulation of kinetic dolomite dissolution match those observed in the experiments when the surface area is three to five orders of magnitude lower than the surface area of the samples measured by gas adsorption.     

A thermodynamic model for the prediction of phase equilibria and speciation in the H2O-CO2-NaCl-CaCO3-CaSO4 system from 0 to 250 °C, 1 to 1000 bar with NaCl concentrations up to halite saturation

A thermodynamic model is developed for the calculation of both phase and speciation equilibrium in the H₂O-CO₂-NaCl-CaCO₃-CaSO₄ system from 0 to 250 °C, and from 1 to 1000 bar with NaCl concentrations up to the saturation of halite. The vapor-liquid-solid (calcite, gypsum, anhydrite and halite) equilibrium together with the chemical equilibrium of H⁺,Na⁺,Ca²⁺, , , and CaSO_4(aq) in the aqueous liquid phase as a function of temperature, pressure and salt concentrations can be calculated with accuracy close to the experimental results.Based on this model validated from experimental data, it can be seen that temperature, pressure and salinity all have significant effects on pH, alkalinity and speciations of aqueous solutions and on the solubility of calcite, halite, anhydrite and gypsum. The solubility of anhydrite and gypsum will decrease as temperature increases (e.g. the solubility will decrease by 90% from 360 K to 460 K). The increase of pressure may increase the solubility of sulphate minerals (e.g. gypsum solubility increases by about 20-40% from vapor pressure to 600 bar). Addition of NaCl to the solution may increase mineral solubility up to about 3 molality of NaCl, adding more NaCl beyond that may slightly decrease its solubility. Dissolved CO₂ in solution may decrease the solubility of minerals. The influence of dissolved calcite on the solubility of gypsum and anhydrite can be ignored, but dissolved gypsum or anhydrite has a big influence on the calcite solubility. Online calculation is made available on www.geochem-model.org/model.     

Formation mechanisms of calcite cements in tight sandstones of the Jurassic Lianggaoshan Formation,northeastern Central Sichuan Basin

The characteristics and formation mechanism of calcite cements in the tight sandstone of the Jurassic Lianggaoshan Formation in the northeastern Central Sichuan Basin were analysed using petrographic and isotopic techniques. In the tight sandstone of the Lianggaoshan Formation, cements are mostly calcite and occur as poikilitic, pore-filling, fracture-filling and replacement of clastic particles. Contents of Al, Si, Fe and Mn in the poikilitic calcites are significantly less than that in the dissolution pore-filling and metasomatic calcites. Three stages (early, middle and late) of authigenic calcites correspond to temperature ranges of <60, 60–100 and ≥100?°C, respectively, with most calcite cements formed under lower temperature (<100?°C) conditions. The δ¹⁸O values of the early–middle authigenic calcites are in equilibrium with connate water, and the δ¹⁸O values of late calcites are depleted in ¹⁸O indicating equilibrium at higher temperatures. The early authigenic calcites precipitated in a relatively open system associated with CO₂ from bacterial fermentation at an immature to low-mature stage, and a Ca²⁺- and alkaline-rich environment owing to hydration–hydrolysis and dissolution of silicate minerals during phase A of eodiagenesis. The middle–late authigenic calcites precipitated in a relatively closed system with CO₂ from decarboxylation of organic acids and Ca²⁺ from dissolution of silicate minerals and transformation of clay minerals during phase B of eodiagenesis to mesodiagenesis. Calcite cements mainly occur in the medium and fine sandstones of sand flats and beach bars. Authigenic calcite dissolution is extremely weak, and calcite cementation is pore-space destructive.     

Étude expérimentale de la réactivité du CO2 supercritique vis-à-vis de phases minérales pures. Implications pour la séquestration géologique de CO2

Carbon dioxide sequestration in deep aquifers and depleted oilfields is a potential technical solution for reducing green-house gas release to the atmosphere: the gas containment relies on several trapping mechanisms (supercritical CO₂, CO_2(sc), dissolution together with slow water flows, mineral trapping) and on a low permeability cap-rock to prevent CO_2(sc), which is less dense than the formation water, from leaking upwards. A leakproof cap-rock is thus essential to ensure the sequestration efficiency. It is also crucial for safety assessment to identify and assess potential alteration processes that may damage the cap-rock properties: chemical alteration, fracture reactivation, degradation of injection borehole seals, etc. The reactivity of the host-rock minerals with the supercritical CO₂ fluid is one of the potential mechanisms, but it is altogether unknown. Reactivity tests have been carried out under such conditions, consisting of batch reactions between pure minerals and anhydrous supercritical CO₂, or a two-phase CO₂/H₂O fluid at 200?°C and 105/160 bar. After 45 to 60 days, evidence of appreciable mineral-fluid reactivity was identified, including in the water-free experiments. For the mixed H₂O/CO₂ experiments, portlandite was totally transformed into calcite; anorthite displayed many dissolution patterns associated with calcite, aragonite, tridymite and smectite precipitations. For the anhydrous CO₂ experiments, portlandite was totally carbonated to form calcite and aragonite; anorthite also displayed surface alteration patterns with secondary precipitation of fibrous calcite. To cite this article: O. Regnault et al., C. R. Geoscience 337 (2005).     

Using non-conservative tracers to characterise karstification processes in the Merinos-Colorado-Carrasco carbonate aquifer system (southern Spain)

The systematic sampling of the chemical composition of the groundwater from five karst springs (including an overflow spring) and one outflowing borehole have permitted to determine distinctive chemical changes in the waters that reflect the geochemical processes occurring in a carbonate aquifer system from southern Spain. The analysis of the dissolution parameters revealed that geochemical evolution of the karst waters basically depends on the availability of the minerals forming aquifer rocks and the residence time within the aquifers. In the three proposed scenarios in the aquifers, which include the preferential flow routines, the more important geochemical processes taking place during the groundwater flow from the recharge to the discharge zones are: CO₂ dissolution and exsolution (outgassing), calcite net dissolution, calcite and dolomite sequential dissolution, gypsum/anhydrite and halite dissolution, de-dolomitization and calcite precipitation. A detailed analysis of the hydrochemical data set, saturation indices of the minerals and partial pressure of CO₂ in the waters joined to the application of geochemical modelling methods allowed the elaboration of a hydrogeochemical model of the studied aquifers. The developed approach contributes to a better understanding of the karstification processes and the hydrogeological functioning of carbonate aquifers, the latter being a crucial aspect for the suitable management of the water resources.     

Navajo Sandstone–brine–CO<Subscript>2</Subscript> interaction: implications for geological carbon sequestration

The injection of CO₂ into deep saline aquifers is being considered as an option for greenhouse gas mitigation. However, the response of an aquifer to the injected CO₂ is largely unknown. Experiments involving the reaction of Navajo Sandstone with acidic brine were conducted at 200°C and 25 or 30 MPa to evaluate the extent of fluid–rock interactions. The first experiment examined sandstone interaction with CO₂-impregnated brine; the second experiment examined sandstone dissolution in CO₂-free acidic brine; the third one is carried out in a mixed-flow reactor and designed to measure sandstone dissolution rates based on time-series Si concentrations. The solution chemistry data indicate that the SiO₂(aq) increases gradually and pH increases slowly with reaction progress. Silicate minerals in the sandstone display textures (dissolution features, secondary mineralization), indicating that these phases are reacting strongly with the fluid. Dissolution of feldspars and conversion of smectite to illite are likely to be the two reactions that contribute to the release of SiO₂(aq). The product minerals present at the end of the experiments are illite, illite/smectite, allophane, and carbonate minerals (for the CO₂-charged system). Dissolved CO₂ is likely to acidify the brine and to provide a source of carbon for the precipitation of carbonate minerals. Mineral trapping through the precipitation of carbonate minerals is favored thermodynamically and was observed in the experiments. The chemical reactions likely increase the bulk porosity of the sandstone due to dissolution of silicate minerals. However, allophane and illite/smectite fill voids in sandstone grains. There is no evidence for the removal of clay coatings due to chemical reactions. It is uncertain whether the mechanical forces near an injection well would mobilize the smectite and allophane and clog pore throats. Trace amounts of metals, including Cu, Zn, and Ba, were mobilized.     

Carbonate dissolution in Mesozoic sand- and claystones as a response to CO2 exposure at 70 °C and 20 MPa

The response to CO₂ exposure of a variety of carbonate cemented rocks has been investigated using pressurised batch experiments conducted under simulated reservoir conditions, 70 °C and 20 MPa, and with a durations of up to14 months. Calcite, dolomite, ankerite and siderite cement were present in the unreacted reservoir rocks and caprocks. Core plugs of the reservoir rocks were used in order to investigate the alterations in situ. Crushing of the caprock samples was necessary to maximise reactions within the relatively short duration of the laboratory experiments. Synthetic brines were constructed for each batch experiment to match the specific formation water composition known from the reservoir and caprock formations in each well. Chemical matched synthetic brines proved crucial in order to avoid reactions due to non-equilibra of the fluids with the rock samples, for example observations of the dissolution of anhydrite, which were not associated with the CO₂ injection, but rather caused by mismatched brines.Carbonate dissolution as a response to CO₂ injection was confirmed in all batch experiments by both petrographical observations and geochemical changes in the brines. Increased Ca and Mg concentrations after 1 month reaction with CO₂ and crushed caprocks are ascribed to calcite and dolomite dissolution, respectively, though not verified petrographically. Ankerite and possible siderite dissolution in the sandstone plugs are observed petrographically after 7 months reaction with CO₂; and are accompanied by increased Fe and Mn contents in the reacted fluids. Clear evidence for calcite dissolution in sandstone plugs is observed petrographically after 14 months of reaction with CO₂, and is associated with increased amounts of Ca (and Mg) in the reacted fluid. Dolomite in sandstones shows only minor dissolution features, which are not clearly supported by increased Mg content in the reacted fluid.Silicate dissolution cannot be demonstrated, either by chemical changes in the fluids, as Si and Al concentrations remain below the analytical detection limits, nor by petrographical changes, as partly dissolved feldspar grains and authigenic analcime are present in the sediments prior to the experiments. It is noteworthy, that authigenic K-feldspar and authigenic albite in sandstones show no signs of dissolution and consequently seem to be stable under the experimental conditions.