Brine Rock Interactions Research Articles

Experimental Study on Co2–Brine–Rock Interaction Altering Mineralogical, Physical, and Mechanical Properties of Carbonate-Rich Shale Oil Reservoirs

Experimental Study on Co2–Brine–Rock Interaction Altering Mineralogical, Physical, and Mechanical Properties of Carbonate-Rich Shale Oil Reservoirs

Influence of CO2-brine-rock Interactions on the Physical Properties of Tight Sandstone Cores via Nuclear Magnetic Resonance

For sandstone reservoirs with extra-low permeability, CO2 injection is regarded as a valid method to enhance oil recovery. When CO2 injection is implemented in such reservoirs, the physical properties of the formation could be altered owing to the interactions between CO2, water, and rock. In this study, the influence of CO2–brine–rock interactions on the physical properties of tight sandstone cores was analyzed by comparing the obtained T 2 spectrum before and after CO2 injection. The results revealed that the T2 spectrum after CO2 injection was significantly different from the original T2 spectrum. CO2 injection changed the pore size distribution of the core samples. When the injection pressure was low, the pore volume decreased from micropores to macropores leading to a decrease in both permeability and porosity. As the injection pressure increasing, the dissolution of CO2 in the micropores was enhanced thus improving the pore-throat connectivity; which ultimately improved the reservoir physical properties.

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples.

Pore Structure and Seal Capacity of Ilaro Formation Shales in the Eastern Dahomey Basin: Implications from Mercury Injection Capillary Pressure and Spontaneous Imbibition Analyses

A petrophysical evaluation of caprock pore characteristics and seal capacity is critical for geologic storage of CO2. In this study, integration of X-ray diffraction, mercury injection capillary pressure (MICP), and spontaneous imbibition analyses is used to evaluate the pore characteristics and seal capacity of shale samples from the Ilaro formation, which could serve as a seal for CO2 injected into the reservoir units of the eastern Dahomey basin. X-ray diffraction reveals the samples as clay-rich and early diagenetic, while spontaneous imbibition reveals pore connectivity heterogeneity. MICP analysis shows the samples as being characterized by a low breakthrough pressure and reveals the mesopore dominance with majority of pore volumes dominated by 5 to 10 nm-sized pore throats. Furthermore, high CO2 column heights are obtained from conversion of MICP data (at 20% saturation) for mesopore-dominated samples containing ankerite and kaolinite. The study reveals that should injected CO2 migrate upward from the reservoir units of the onshore eastern Dahomey basin, portions of the Ilaro formation may function as a good seal due to the mesopore mineralogical composition influence on the CO2–brine–rock interaction. This result should therefore serve as an important insight for future caprock sealing studies conducted on the onshore eastern Dahomey basin.

Adsorption of Crude Oil Components onto Carbonate and Sandstone Outcrop Rocks and Its Effect on Wettability

The processes of establishing and altering reservoir wettability are still subjects of discussion due to the complexity of the underlying crude oil–brine–rock interactions. This study was aimed at ...

Modeling interaction between CO2, brine and chalk reservoir rock including temperature effect on petrophysical properties

Carbon dioxide (CO2) capture and sequestration through CO2 enhanced oil recovery (EOR) in oil reservoirs is one of the approaches considered to reduce CO2 emission into the atmosphere. The injection of CO2 into a subsurface geological formation may lead to chemical reactions that may affect the formation pore structure and characteristics. In this study, the effect of CO2–brine–rock interaction on the rock petrophysical properties and mineral volume fraction was numerically investigated during CO2 injection into a chalk reservoir rock. A 3D numerical modeling and simulation were conducted using COMSOL® Multiphysics commercial software of computational fluid dynamics (CFD) to simulate CO2–brine core flooding process in a chalk core. The model was validated against a core–scale experimental data from literature. Simulation differential pressure data matched the literature experimental data closely and consistently indicating good agreement between them. Temperature effect on the performance of CO2–brine–chalk sequestration was also evaluated in the present study. Results indicated that porosity was only slightly affected by temperature increase during CO2 injection in contrast to permeability that was substantially affected by temperature. Moreover, chemical reactions enhanced as temperature increased leading to significant increase in permeability. Thus, carbonated brine sequestration excelled at elevated temperature due to increased acidity which governs the sequestration process. The developed model maybe considered as a reliable tool to optimize various operating parameters of CO2–brine sequestration.

Role of ion exchange in the brine-rock interaction systems: A detailed geochemical modeling study

The flow of brine through porous rocks is a common phenomenon in nature and industry. Reactive species of the brine and rock minerals interact with each other during the brine flow. These interactions include precipitation, dissolution, and ion exchange at the rock surface. In the present paper, PHREEQC geochemical package has been used to study the impact of ion exchange in the brine-rock interaction systems. The PHREEQC batch-reaction was employed for modeling the static systems and a geochemical-transport approach was used for modeling the geochemical reactions in the dynamic systems (core-flooding). The impact of ion exchange on effluent concentrations of the reactive species and mass variation of the rock minerals was studied for both sandstone and carbonate rocks. This paper provides an extensive study to achieve more insight into the ion exchange at the rock surface and its impact on the porosity of the porous media. The modeling study shows that the higher ion exchange intensifies the dissolution of the reacting rock minerals. Increasing the exchanger site extends the injection time required to stabilize the system. In addition, it is observed that increasing the salinity of the injected brine weakens the impact of ion exchange on the effluent concentration of the reactive species. The results of this study indicate that during injection of high salinity seawater into a carbonate rock 10% of the porosity enhancement is caused by ion exchange, while 92% of the porosity enhancement is due to the ion exchange when injecting 50 times diluted seawater.

Influence of pH on Acidic Oil–Brine–Carbonate Adhesion Using Atomic Force Microscopy

Wettability alteration seems to be the main physicochemical process during low salinity water injection in carbonate formations. A pH increase due to calcite dissolution during low salinity water injection may affect oil–brine–rock interaction and thereby wettability. However, far too little attention has been paid to quantifying the impact of such an pH increase on acidic oil–carbonate adhesion. Therefore, we measured contact angles between acidic oil (−COOH) and calcite crystal in the presence of 10 000 ppm NaCl solutions at different pHs (6.5, 9.5 and 11) at ambient conditions. Furthermore, we used atomic force microscopy (AFM) to measure the adhesion force between acidic oil groups (−COOH) and calcite substrate at different pHs (9.5 and 11) at similar conditions of the contact angle experiments. Moreover, to confirm the contact angle and AFM results, we measured the zeta potential of acidic oil−brine and calcite−brine interfaces at the same condition and calculated the thermodynamic isotherm disjoining pressure. Our results show that the contact angle reduces from 134 to 95° as the pH increases from 6.5 to 11, increasing hydrophilicity. Adhesion force measurements show that increasing pH reduces the adhesion force between the acidic oil and carbonate in line with contact angle results. Zeta potential results show that increasing the pH increases the negativity of the zeta potential of acidic oil–brine and calcite–brine interfaces, implying the increase of the electrical double layer force. Furthermore, the total disjoining pressure isotherm becomes less negative with increasing pH, implying an increase of hydrophilicity. Taken together, our results confirm that a local pH increase due to calcite dissolution during low salinity water injection would prevail in the wettability alteration process in particular for high acidic oil bearing carbonate reservoirs.

Preliminary geochemical investigation of a possible CO2 injection in the Ungaran geothermal field, Indonesia: equilibrium and kinetic modeling

AbstractCarbon capture and storage (CCS) is considered to be an effective method to mitigate anthropogenic carbon emissions that have been the major cause of global warming. One of the possible sites to store CO2 is in geothermal reservoirs. In this study, an attempt to simulate CO2–brine reservoir rock interaction inside a geothermal reservoir is carried out using the PHREEQC program. The study utilizes published rock mineralogy of the assumed reservoir lithology and chemistry of the hot water in the Ungaran geothermal field, Java, Indonesia. The simulation is based on equilibrium and kinetic modeling and assumes a single stage CO2 injection kept at a constant temperature and pressure. The amount of injected CO2 is determined by solubility modeling of CO2 in hot water under estimated reservoir conditions. The modeling predicted (i) the effect of solubility trapping at early stages of CO2–brine rock interaction, (ii) dissolution of Ca‐bearing silicates (plagioclases) coupled with calcite precipitation as a potential chemical processes relevant to a possible CO2 mineralization, (iii) progressive transition from solubility to mineral trapping becoming significant after 30 days following injection, (iv) minor porosity increase (∼0.5%), and (v) achievement of equilibrium between CO2–brine‐rock in 10 years after injection. Sensitivity analysis associated with the uncertainties for altering mineral proportion and rock porosity reveal no significant change in the ability of the modeled reservoir to trap injected CO2 into mineral phases. Concerning the CCS studies so far carried out in geothermal fields in volcanic reservoirs, this modeling comprises one of the first performed for fields with intermediate volcanics. The result from this study can be utilized as foreknowledge for possible future CCS operations in Indonesian geothermal fields. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Experimental investigation of CO2–brine–rock interactions in relation with CO2 sequestration in an Iranian oil reservoir

AbstractThe main purpose of this study is to evaluate the feasibility of geologic CO2 sequestration in terms of CO2‐brine‐rock interactions in Ramin oil field, Iran. Static experiments were conducted with carbonate rocks at 70°C and atmospheric pressure for 14, 30, and 60 days. CO2‐brine‐rock interactions were inferred from the evaluation of Ca2+, Mg2+, , and concentrations and a thorough characterization of the carbonate rocks before and after treatment. Scanning electron microscopy (SEM) micrographs revealed the formation of dissolution pits and the growth of new structures. Energy dispersive X‐ray spectroscopy (EDS) and X‐ray diffraction (XRD) indicated these minerals to be calcite. Porosity of the carbonate rocks increased from an initial value of 4.72% to the maximum value of 11.83%. Then, it decreased to a value of 5.48% until the end of the experiments, that is, 60 days. Chemical analysis of brine suggested the precipitation and dissolution of calcium sulfate. In addition, dolomite dissolution and halite precipitation/dissolution were inferred. Calcite precipitation and porosity reduction suggested that CO2 can be stored via mineral entrapment in the Ramin oil field, which is desired from the perspective of CO2 geologic sequestration. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Mineral Carbonation of CO2 in Mafic Plutonic Rocks, II—Laboratory Experiments on Early-Phase Supercritical CO2‒Brine‒Rock Interactions

The potential for mineral carbonation of CO2 in plutonic mafic rocks is addressed through a set of laboratory experiments on cumulate gabbro and gabbro-diorite specimens from the Sines Massif (Portugal). The experiments were conducted in an autoclave, for a maximum of 64 days, using a CO2 supersaturated brine under pressure and temperature conditions similar to those expected around an injection well during early-phase CO2 injection. Multiple techniques for mineralogical and geochemical characterization were applied ante- and post-carbonation experiments. New mineralogical phases (smectite, halite and gypsum), roughness increase and material loss were observed after exposure to the CO2 supersaturated brine. The chemical analysis shows consistent changes in the brine and rock specimens: (i) increases in iron (Fe) and magnesium (Mg) in the aqueous phase and decreases in Fe2O3 and MgO in the specimens; (ii) a decrease in aqueous calcium (Ca) and an increase in CaO in the cumulate gabbro, whereas in the gabbro-diorite aqueous Ca increased and afterwards remained constant, whereas CaO decreased. The geochemical model using the CrunchFlow code was able to reproduce the experimental observations and simulate the chemical behavior for longer times. Overall, the study indicates that the early-stage CO2 injection conditions adopted induce mainly a dissolution phase with mineralogical/textural readjustments on the external area of the samples studied.

Experimental and numerical investigation of CO2–brine–rock interactions in the early Palaeozoic mudstones from the Polish part of the Baltic Basin at simulatedin situ conditions

AbstractThis study discusses experiment‐induced alterations of shale rocks collected across the ordovician and silurian boundary at a potential site for carbon dioxide sequestration located in the Polish part of the Baltic Basin. Mudstone samples submerged in brine in custom‐built reactors were subjected to CO2 pressures of 30–35 MPa at a temperature of 80°C for 40 days. After the experiments were completed, the mineralogical composition of the studied rocks, their porosity characteristics, and chemistry of brines were analyzed and compared to the original compositions in order to detect experiment‐induced changes. Comparison of mineral composition before and after the experiments demonstrate a set of subtle but systematic mineral changes. The most conspicuous was a presence of Fe in the form of Fe‐oxyhydroxides that was related to the corrosion of the Fe‐bearing steel pipes supplying the experimental setup with CO2. This effect is important from the perspective of industrial carbon dioxide sequestration. However, the second source of Fe ions in experimental brines was related to the decomposition of chlorites, pyrite, and chloritized biotites. The suggested breakdown of pyrite is in line with the modification of the chemical composition of the experimental brines and observed transfer of S ions to the solution. The appearance of Mg and K ions in the experimental brines was related to the decomposition of chlorites and biotites. In turn, observed transfer of Sr cations to the solution could be attributed to the dissolution of biotites and K‐feldspars. The effects of analogue experiments were confronted with the results of geochemical modeling performed using the PHREEQC program. The numerical modeling not only allowed to reproduce all the main mineral and chemical changes postulated on the basis of our analogue experiment, but also enabled to put constraints on the time scale of occurring geochemical processes. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Pore structure alteration induced by CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs

CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2–brine–rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2–brine–rock interaction generated many large pores (10–50 μm) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1–6 μm) and some microfractures in clays. The T2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2–brine–rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T2 distributions transformed into apparent dual-peak T2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 °C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 μm to 0.166 μm, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.

Effects of geochemical reactions on multi-phase flow in porous media during CO2 injection

Impacts of fluid-rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multiphase flow behaviour of porous media and therefore on CO2 injectivity and residual trapping potential are yet unknown. We found that CO2-saturated brine-rock interactions in a carbonate rock increased the grains roughness, increased the population of micro and macro pores and decreased the pore volume of medium size pores. These changes in pore structure led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeabilities cross point toward more water-wet condition. Finally, these reaction-induced pore structure changes caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage. Considering these fluid-rock reaction-induced changes is essential for accurate prediction/simulation of reservoir behaviour and risk analysis of the project.

Detailed analysis of the brine-rock interactions during low salinity water injection by a coupled geochemical-transport model

Enhanced Oil Recovery (EOR) methods have been widely used around the world to improve oil production from petroleum reservoirs. Recently, the injection of the low salinity/smart water has gained popularity among the EOR methods. Different mechanisms are believed to exist during low salinity/smart water injection, including dissolution, precipitation, and ion exchange at the rock surface. In this study, a coupled geochemical-transport model is presented for the detailed analysis and investigation of the interactions between brine, sandstone and carbonate rocks. The proposed model presents the coupling of a geochemical software (PHREEQC) and a species transport model. This coupled method makes it possible to model the dissolution, precipitation, and ion exchange caused by geochemical reactions during water flow through porous media. The results show that monovalent cations are released into the brine from the exchanger site, and divalent cations fill their position at the clay surface for the sandstone rock. The porosity and permeability changes are observed in the carbonate rock, where it can be important in the near injection area. The ion exchange results in the carbonate rocks show that the geochemical reactions move in a direction to disagree with the pH increase created by low salinity brine injection.

Oil production and reservoir damage during miscible CO2 injection

The blockage and alteration of wettability in reservoirs caused by asphaltene deposits are problems that contribute to poor oil recovery performance during carbon dioxide (CO2) injection. Oil production and reservoir damage are both controlled by macroscopic interlayer heterogeneity and microscopic pore-throat structure and may be optimized by the choice of flooding method. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments on a model heterogeneous three-layer reservoir. For CO2, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, while the permeability decline due to formation damage is larger in the high-permeability layer. We found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding lower oil recovery and greater decreases in permeability. However, it was found that the degree of water wetness for cores with larger, more connected pore-throat microstructures became weaker due to asphaltene precipitation to pore surfaces. Decreasing the degree of water wetness was found to be exacerbated by increases in the sweep volume of injected CO2 that arise from cores with larger and better connected pore throats. Erosion of water wetness is a disadvantage for enhanced oil recovery operations as asphaltene precipitation prevention and control measures become more necessary.

Changes in multi-phase flow properties of carbonate porous media during CO2 injection

Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.

Modeling geologic sequestration of carbon dioxide in a deep saline carbonate reservoir with TOUGH2–ChemPlugin, a new tool for reactive transport modeling

This paper outlines the development and demonstration of a new tool, TOUGH2–ChemPlugin (T2CPI) for predicting rock–water–CO2 interaction following injection of supercritical CO2 into a heterogeneous carbonate system. Specifically, modeling capabilities of TOUGH2, which examines multiphase flow and supercritical CO2 behavior, were combined with the geochemical modeling capabilities of The Geochemist’s Workbench® (GWB), using ChemPluginTM. ChemPlugin is a self-linking re-entrant software object that, when coupled to a transport simulator, retains the flow and transport capabilities of the simulator but enables incorporation of reactive chemistry via GWB. To test and assess the capabilities of T2CPI, results from T2CPI simulations were compared to those of TOUGHREACT, using the same carbonate reservoir parameters (based on the Dollar Bay Formation of the South Florida Basin). Overall, results of simulations from TOUGHREACT and T2CPI were very similar for nearly all evaluated parameters. Dissimilarities between the two programs included qualitative differences in how TOUGHREACT and T2CPI predicted calcite dissolution and the subsequent spatial pattern of the porosity gain caused by how each handles evaporation of water near the injection point. The TOUGHREACT program is a proven, widely used tool for evaluating CO2–brine–rock interaction following supercritical CO2 injection. The T2CPI tool offers similar capabilities and strengths of TOUGHREACT, with the ability to read in and use databases for a wide range of activity coefficient types. This program also has abilities to use a wide range of kinetic constraints, define those kinetic constraints with scripts or compiled libraries, account for colloidal transport, and/or account for a wide range of surface sorption models.

Understanding of Long-Term CO2-Brine-Rock Geochemical Reactions Using Numerical Modeling and Natural Analogue Study

To further understand the interactions of CO2-brine-rock at geological time scales, in this study, a 1D reactive transport model of CO2 intrusion into sandstone of the Longtan Formation (P2l) in the Huangqiao area, China, was constructed based on site-specific data. The simulation time is consistent with the retention time of CO2 in the Longtan sandstone Formation and is set to 20 Ma. The reactive transport model is calibrated and revised using the measured data for sandstone samples from Well X3 (i.e., the natural analogue). By comparing the simulation results with measured data for the natural analogue, the long-term geochemical reactions are investigated. The simulation results indicate that the brine-rock interactions induced by CO2 can be roughly divided into two stages. First, susceptible minerals (e.g., chlorite, ankerite, calcite, and feldspar minerals) dissolve rapidly under acidic conditions formed by the dissolution of CO2. The precipitation of siderite is facilitated by the dissolution of ankerite and chlorite. Smectite-Ca and dawsonite precipitate due to the dissolution of anorthite and albite, respectively. Dawsonite begins to convert into smectite-Na when albite is completely dissolved. As the reactions continue, intermediate products (i.e., illite, smectite-Na, and smectite-Ca) generated in the first stage become the reactants and subsequently react with CO2 and brine. These three clay minerals are not stable under acidic conditions and transform into kaolinite and paragenetic quartz in the later stage of reaction. Comparing the simulation results of the Base Case with the measured data for the natural analogue and inspired by previous studies, the scour of kaolinite is supposed to have occurred in this region and is considered in the revised model by introducing a coefficient of the scour of kaolinite (i.e., Case 2). The simulation results of Case 2 fit well with the measured data on mineral assemblage, and the trend of the sandstone porosity growth caused by the CO2-brine-rock reaction is captured by our simulation results. The combination of numerical simulation and natural analogue study indicates that the joint effects of long-term CO2-brine-rock reactions and scour of kaolinite increase the pore space of the host rock and result in an increase in quartz content in the sandstone.

Experimental Investigation and Numerical Simulation of CO2–Brine–Rock Interactions during CO2 Sequestration in a Deep Saline Aquifer

CO2 mineralization is a long-term and secure solution for geological CO2 storage that primarily depends on the CO2–brine–rock interaction during CO2 sequestration in subsurface formations. In this study, lab experiments were conducted to investigate the CO2–brine–rock interaction over short timescales, and numerical simulations were performed to reveal dynamic interactions and equilibrium interactions by applying TOUGHREACT and PHREEQC, respectively. In the experiments, the main ions of HCO3− and Ca2+ were detected in the solution, and calcite dissolution and dawsonite precipitation were observed from SEM images. The simulation results showed that the CO2 dissolution and the solution pH were affected by the temperatures, pressures, types of solutions, and solution concentrations and were further influenced by mineral dissolution and precipitation. The results of the equilibrium simulation showed that the dissolved minerals were albite, anhydrite, calcite, Ca-montmorillonite, illite, K-feldspar, and chlorite, and the precipitated minerals were dolomite, kaolinite, and quartz, which led to HCO3−, K+, and Na+ being the main ions in solutions. The results of the dynamic simulation showed that calcite and dolomite dissolved in the early period, while other minerals began to dissolve or precipitate after 100 years. The dissolved minerals were mainly albite, kaolinite, K-feldspar, and chlorite, and precipitated minerals were Ca-montmorillonite, illite, and quartz. Anhydrite and pyrite did not change during the simulation period, and the main ions were HCO3−, Na+, Ca2+, and Mg2+ in the simulation period. This study provides an effective approach for analyzing the CO2–brine–rock interaction at different stages during CO2 storage, and the results are helpful for understanding the CO2 mineralization processes in deep saline aquifers.