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CO2–water–rock interactions have an important impact on the stability and integrity of the caprock in CO2 geological storage projects. The injected CO2 in the reservoir enters the caprock via different mechanisms, leading to either the dissolution or precipitation of minerals. The mineral alterations change the porosity, permeability, and mechanical properties of the caprock, affecting its sealing capability. To evaluate the sealing effectiveness of overlying caprock and identify the influencing factors, numerical simulations and experiments were carried out on the mudstone Dongying Formation in Dezhou, China. Based on high-temperature and high-pressure autoclave experiments, batch reaction simulations were performed to obtain some key kinetic parameters for mineral dissolution/precipitation. Then, they were applied to the following simulation. The simulation results indicate that gaseous CO2 has migrated 7 m in the caprock, while dissolved CO2 migrated to the top of the caprock. Calcite is the dominant mineral within 1 m of the bottom of the caprock. The dissolution of calcite increases the porosity from 0.0625 to 0.4, but the overall porosity of the caprock decreases, with a minimum of 0.054, mainly due to the precipitation of montmorillonite and K-feldspar. A sensitivity analysis of the factors affecting the sealing performance of the caprock considered the changes in sealing performance under different reservoir sealing conditions. Sensitivity analysis of the factors affecting the sealing performance of the caprock indicates that the difference in pressure between reservoir and caprock affects the range of CO2 transport and the degree of mineral reaction, and the sealing of the caprock increases with the difference in pressure. Increasing the initial reservoir gas saturation can weaken the caprock's self-sealing behavior but shorten the migration distance of CO2 within the caprock. When the content is lower than 2%, the presence of chlorite improves the sealing performance of the caprock and does not increase with further chlorite content. This study elucidates the factors that affect the sealing ability of the caprock, providing a theoretical basis for the selection and safety evaluation of CO2 geological storage sites. [ABSTRACT FROM AUTHOR]

Mechanical softening behaviors of shale in CO2-water–rock interaction are critical for shale gas exploitation and CO2 sequestration. This work investigated the cross-scale mechanical softening of shale triggered by CO2-water–rock interaction. Initially, the mechanical softening of shale following 30 d of exposure to CO2 and water was assessed at the rock-forming mineral scale using nanoindentation. The mechanical alterations of rock-forming minerals, including quartz, muscovite, chlorite, and kaolinite, were analyzed and compared. Subsequently, an accurate grain-based modeling (AGBM) was proposed to upscale the nanoindentation results. Numerical models were generated based on the real microstructure of shale derived from TESCAN integrated minerals analyzer (TIMA) digital images. Mechanical parameters of shale minerals determined by nanoindentation served as input material properties for AGBMs. Finally, numerical simulations of uniaxial compression tests were conducted to investigate the impact of mineral softening on the macroscopic Young’s modulus and uniaxial compressive strength (UCS) of shale. The results present direct evidence of shale mineral softening during CO2-water–rock interaction and explore its influence on the upscale mechanical properties of shale. This paper offers a microscopic perspective for comprehending CO2-water-shale interactions and contributes to the development of a cross-scale mechanical model for shale.

The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO2 saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO2 seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO2 injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO2 injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO2–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies. [ABSTRACT FROM AUTHOR]

IntroductionMantle-derived CO2, as an important component of hydrothermal fluids, is widely distributed in petroliferous basins. While previous experimental studies have suggested that CO2 can improve sandstone reservoir quality through mineral dissolution in open fluid setting, they have overlooked its nagetive effects to sandstone reservoir quality by carbonate cementation. Additionally, the roles of various fluid environments in CO2-reservoir interactions have not been studied in detail.MethodsTo systematically investigate the influences of CO2 on sandstone reservoirs, we examine a typical mantle-derived CO2 gas reservoir, Bohai Bay Basin, China. This study employs integrated methods, including electron microscopy, scanning electron microscopy, X-ray diffraction, stable C- and O-isotope analysis, and physical property data. The aim is to investigate the evidence and mechanisms by which mantle-derived CO2 impacts sandstone reservoirs, particularly focusing on its effects in open and closed fluid environments.Results and DiscussionOur findings reveal that dawsonite and ankerite are prevalent within the mantle-derived CO2 gas reservoir, while isotopic analysis of carbonate cements indicates values (δ13C: −9.0‰ to −1.6‰; δ18O: −21.7‰ to −12.7‰) consistent with mantle-derived CO2 and hydrothermal fluids. These pieces of evidence indicate that CO2-rich hydrothermal fluids participate in water-rock interactions, thereby significantly influencing the diagenesis of reservoirs. Further, we notice that CO2 reservoirs adjacent to faults exhibit an open fluid environment, characterized by superior porosity and permeability, more quartz, but fewer feldspar, carbonate, and clay minerals compared to those in closed fluid environments. Notably, kaolinite predominates in open fluid environments, while illite/smectite (I/S) is more common in closed settings. The dual roles of mantle-derived CO2 are highlighted in our analysis: while it enhances reservoir storage and permeability through mineral dissolution, the carbonate cement generated by CO2-water-rock interaction can also adversely affect reservoir quality. In open fluid environments, CO2 facilitates the dissolution of feldspar and carbonate minerals, promoting the timely removal of dissolution by-products (clay mineral) and inhibiting carbonate cementation, thereby improving reservoir properties. Conversely, in closed fluid environments, decreasing CO2 concentrations with depth leads to diminishing dissolution effects and increased carbonate cementation, resulting in reduced reservoir porosity and permeability. Overall, the significance of this study is to correct the deviation in the impacts of CO2 on sandstone reservoirs at laboratory setting through case study of typical mantle-source CO2 gas reservoir.This work can be applied to the studies of reservoir homogeneity and sweet spots in regions with hydrothermal and mantle-derived CO2 activities. However, due to the limitation of CO2 content range (about 15%–70%) in the study case, we are unable to investigate the effects of low-concentration CO2 on sandstone reservoirs, which may affect the generalizability of this work. Besides, the formation temperature and pressure, and salinity of formation water, should be considered when dealing with other cases.

CO2–water–rock interactions have an important impact on the stability and integrity of the caprock in CO2 geological storage projects. The injected CO2 in the reservoir enters the caprock via different mechanisms, leading to either the dissolution or precipitation of minerals. The mineral alterations change the porosity, permeability, and mechanical properties of the caprock, affecting its sealing capability. To evaluate the sealing effectiveness of overlying caprock and identify the influencing factors, numerical simulations and experiments were carried out on the mudstone Dongying Formation in Dezhou, China. Based on high-temperature and high-pressure autoclave experiments, batch reaction simulations were performed to obtain some key kinetic parameters for mineral dissolution/precipitation. Then, they were applied to the following simulation. The simulation results indicate that gaseous CO2 has migrated 7 m in the caprock, while dissolved CO2 migrated to the top of the caprock. Calcite is the dominant mineral within 1 m of the bottom of the caprock. The dissolution of calcite increases the porosity from 0.0625 to 0.4, but the overall porosity of the caprock decreases, with a minimum of 0.054, mainly due to the precipitation of montmorillonite and K-feldspar. A sensitivity analysis of the factors affecting the sealing performance of the caprock considered the changes in sealing performance under different reservoir sealing conditions. Sensitivity analysis of the factors affecting the sealing performance of the caprock indicates that the difference in pressure between reservoir and caprock affects the range of CO2 transport and the degree of mineral reaction, and the sealing of the caprock increases with the difference in pressure. Increasing the initial reservoir gas saturation can weaken the caprock’s self-sealing behavior but shorten the migration distance of CO2 within the caprock. When the content is lower than 2%, the presence of chlorite improves the sealing performance of the caprock and does not increase with further chlorite content. This study elucidates the factors that affect the sealing ability of the caprock, providing a theoretical basis for the selection and safety evaluation of CO2 geological storage sites.

Understanding the flow characteristics of supercritical CO2 in dry sandstones or those with low water content provides crucial information on the flow behavior in near‐wellbore zone. We conducted supercritical CO2 core flooding experiments using sandstone cores extracted from potential CO2 reservoirs in the Ordos Basin, China. During the experiments, we reduced the water content of saturated cores by flushing with dry CO2 and subsequently vacuumizing them at a temperature of 35°C to simulate sandstones with low water content. The experimental results demonstrate that the CO2 permeability was initially high during the low differential pressure stage and remained constant as the differential pressure increased. In the carbonic acid solution injection experiment, we observed an increase in the flow rate of the solution with the continuous interaction in the cores from the Shanxi and Shihezi groups, while the Yanchang group exhibited the opposite effect. This increase in permeability can be attributed to mineral dissolution and the loss of fine particles. Conversely, the blockage of fine particles or the precipitation of dissolved minerals may lead to a decrease in permeability. After the CO2–water–rock interaction, the CO2 permeability decreased compared to before the interaction, indicating that adsorbed water, the precipitation of dissolved mineral, or pore throat blockage by fine particles could induce this permeability decrease. The impact of adsorbed water on the decrease in CO2 permeability is significant. Additionally, the CO2–water–rock interaction caused corrosion on the anorthite surface. Furthermore, calcite dispersed in connected pores displayed a more pronounced dissolution compared to cemented calcite. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The CO2-water-rock interaction is the core issue of CO2 geological sequestration. The injection of CO2 disrupts the chemical balance of rock-formation water， and the changes in the chemical properties of formation water， primary mineral dissolution， and secondary mineral precipitation will lead to changes in the physical properties of reservoir and caprock， such as porosity， wettability， and mechanical properties and thus directly affect the CO2 injection capacity， sequestration efficiency， and sequestration security and stability. Based on the mechanism of CO2-water-rock interaction， this paper systematically expounds on the research progress of the effects of CO2-water-rock interaction on porosity， permeability， wettability， and mechanical properties of formation rocks. The results show that the change in rock porosity and permeability caused by CO2-water-rock interaction is closely related to its initial porosity and permeability characteristics and mineral composition， and the change of rock porosity and permeability characteristics directly affects the injection capacity and sequestration potential of the reservoir and the sealing capacity of the caprock. The change in wettability is related to the initial hydrophilic and oil-philic characteristics. The CO2-water-rock interaction usually weakens the water wettability of the hydrophilic rocks and enhances that of the oil-philic rocks， thus affecting the microscopic distribution and seepage characteristics of the multiphase fluids in the pores of the rocks. Due to the dissolution of cement and the formation of dissolution holes， the CO2-water-rock interaction will cause rock damage， and the mechanical parameters such as compressive strength， tensile strength， and elastic modulus will decrease. To a certain extent， the security of sequestration is affected. Under the setting of carbon neutrality， the CO2-water-rock interaction and rock physical property response under the scenarios of micro-nano-scale pore， deep microbial mediation， impure CO2 or industrial tail gas injection， and full sequestration cycle still need to be further studied.

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About one million tons of CO2 have been injected into the Farnsworth unit to date. The target reservoir for CO2 injection is the Morrow B Sandstone, which is primarily made of quartz with lesser amounts of albite, calcite, chlorite, and clay minerals. The impact of CO2 injection on the mineralogy, porosity, and pore water composition of the Morrow B Sandstone is a major concern. Although numerical modeling studies suggest that porosity changes will be minimal, significant alterations to mineralogy and pore water composition are expected. Given the implications for CO2 storage effectiveness and risk assessment, it is crucial to verify the accuracy of theoretical model predictions through laboratory experiments. To this end, batch reaction experiments were conducted to model conditions near an injection well in the Morrow B Sandstone and at locations further away, where the CO2 has been diluted by formation water. The laboratory experiments involved submerging thin sections of both coarse- and fine-grained facies of the Morrow B Sandstone in formation water samples with varying levels of CO2. The experiments were conducted at the reservoir temperature of 75 °C. Two experimental runs were conducted, one lasting for 61 days and the other for 72 days. The initial fluid composition used in the second run was the same as in the first. The mineralogy changes in the thin sections were analyzed using SEM and the Tescan Integrated Mineral Analyzer (TIMA), while changes in the composition of the formation water were determined using ICP-AES. During each experiment, a thin layer of white fine-grained particles consisting mainly of dolomite and silica formed on the surface of the thin sections, leading to significant reductions in Ca, Mg, and Sr in the formation water. This outcome is consistent with numerical model predictions that dolomite would be the primary mineral that would react with injected CO2 and that silica would be oversaturated in the formation water. Changes in mineral abundance in the thin sections themselves were much less systematic than in the theoretical modeling experiments, perhaps reflecting heterogeneities in the mineral grain size surface area to volume ratios and mineral distributions in the thin sections not considered in the numerical models. [ABSTRACT FROM AUTHOR]

To investigate the impacts of mineral composition on physical and mechanical properties of carbonate rocks, limestone specimens containing different contents in calcite and dolomite are selected to perform CO2‐water‐rock reaction experiments. The X‐ray Diffraction (XRD) and Nuclear Magnetic Resonance (NMR) are carried out to examine the change characteristics of mineral dissolution and pore structure after reaction. The core flooding experiments with Fiber Bragg gratings are implemented to examine the stress sensitivity of carbonate rocks. The results show that the limestones containing pure calcite are more susceptible to acid dissolution compared to limestone containing impure dolomite. The calcite content in pure limestone decreases as the reaction undergoes. The dissolution of dolomite leads to the formation of calcite in impure limestone. Calcite dissolution leads to the formation of macropore and flow channels in pure limestone, while the effects of impure dolomite in impure limestone results in mesopore formation. When confining pressure is lower than 12 MPa, pure limestones demonstrate higher strain sensitivity coefficients compared to impure limestone containing dolomite after reaction. When confining pressure exceeds 12 MPa, the strain sensitivity coefficients of both pure and impure limestones become almost equal. [ABSTRACT FROM AUTHOR]

• A 3D model of multiphase reactive flow with solid dissolution is proposed. • The diagram of multiphase reactive flow including several patterns is established. • A new correlation of reactive surface area-porosity-saturation is formulated. • Different pore size distributions and bubble characteristics are quantified. • The mass transfer coefficient and effective reaction rate are evaluated. There are still many unclear mechanisms in the multiphase reactive flow with solid dissolution processes. In this study, the reactive transport processes coupled with solid dissolution and self-induced multiphase flow in three-dimensional (3D) structures with increasing complexity is studied by developing a 3D computational microfluidic method, which considers multiphase flow, interfacial mass transport, heterogeneous chemical reactions, and solid structure evolution. Solid dissolution diagram in a simple channel in the framework of multiphase flow is proposed, with six coupled multiphase flow and solid dissolution patterns identified and the transition between different patterns discussed. Then, multiphase reactive flow in a porous chip is further studied, and the interesting 3D phenomena are discovered, including enhanced solid dissolution in the middle and enriched bubble generation at the corner along the thickness direction. Considering the importance of reactive surface area, correlations of reactive surface area-porosity-saturation with different dissolution patterns are proposed based on the pore-scale results. Finally, the computational microfluidic model is extended to investigate the multiphase reactive flow in a 3D digital core. Different dissolution patterns are recognized using the local porosity evolution character, and the corresponding pore size distribution and bubble characteristics are deciphered. These findings advance understanding of multiphase reactive transport processes and contribute to improve continuum-scale reactive transport modeling. Computational microfluidic study of multiphase reactive flow with solid dissolution and bubble generation in a simple channel, a microfluidic porous chip, and a digital core. [Display omitted] [ABSTRACT FROM AUTHOR]

About one million tons of CO2 have been injected into the Farnsworth unit to date. The target reservoir for CO2 injection is the Morrow B Sandstone, which is primarily made of quartz with lesser amounts of albite, calcite, chlorite, and clay minerals. The impact of CO2 injection on the mineralogy, porosity, and pore water composition of the Morrow B Sandstone is a major concern. Although numerical modeling studies suggest that porosity changes will be minimal, significant alterations to mineralogy and pore water composition are expected. Given the implications for CO2 storage effectiveness and risk assessment, it is crucial to verify the accuracy of theoretical model predictions through laboratory experiments. To this end, batch reaction experiments were conducted to model conditions near an injection well in the Morrow B Sandstone and at locations further away, where the CO2 has been diluted by formation water. The laboratory experiments involved submerging thin sections of both coarse- and fine-grained facies of the Morrow B Sandstone in formation water samples with varying levels of CO2. The experiments were conducted at the reservoir temperature of 75 °C. Two experimental runs were conducted, one lasting for 61 days and the other for 72 days. The initial fluid composition used in the second run was the same as in the first. The mineralogy changes in the thin sections were analyzed using SEM and the Tescan Integrated Mineral Analyzer (TIMA), while changes in the composition of the formation water were determined using ICP-AES. During each experiment, a thin layer of white fine-grained particles consisting mainly of dolomite and silica formed on the surface of the thin sections, leading to significant reductions in Ca, Mg, and Sr in the formation water. This outcome is consistent with numerical model predictions that dolomite would be the primary mineral that would react with injected CO2 and that silica would be oversaturated in the formation water. Changes in mineral abundance in the thin sections themselves were much less systematic than in the theoretical modeling experiments, perhaps reflecting heterogeneities in the mineral grain size surface area to volume ratios and mineral distributions in the thin sections not considered in the numerical models.

The stability of dawsonite is an important factor affecting the feasibility evaluation of CO2 geological storage. In this paper, a series of experiments on the interaction of CO2-water-dawsonite-bearing sandstone were carried out under different CO2 pressures. Considering the dissolution morphology and element composition of dawsonite after the experiment and the fluid evolution in equilibrium with dawsonite, the corrosion mechanism of dawsonite led by CO2 partial pressure was discussed. The CO2 fugacity of the vapor phase in the system was calculated using the Peng-Robinson equation of state combined with the van der Waals 1-fluid mixing rule. The experimental results indicated that the thermodynamic stability of dawsonite increased with the increase of CO2 partial pressure and decreased with the increase of temperature. The temperature at which dawsonite dissolution occurred was higher at higher f CO 2 . There were two different ways to reduce dawsonite's stability: the transformation of constituent elements and crystal structure damage. Dawsonite undergoes component element transformation and crystal structure damage under different CO2 pressures with certain temperature limits. Based on the comparison of the corrosion temperature of dawsonite, three corrosion evolution models of dawsonite under low, medium, and high CO2 pressures were summarized. Under conditions of medium and low CO2 pressure, as the temperature continued to increase and exceeded its stability limit, the dawsonite crystal structure was corroded first. Then the constituent elements of dawsonite dissolved, and the transformation of dawsonite to gibbsite began. At high CO2 pressure, the constituent elements of dawsonite dissolved first with the increase of temperature, forming gibbsite, followed by the corrosion of crystalline structure. [ABSTRACT FROM AUTHOR]

• Ratio of solid–liquid contact area is directly proportional to pore pressure. • Presence of pore pressure shows more obvious effect than further increase. • Error of modified kinetics equation is 33.60% lower than original one. • Interaction at certain pressure can be used to forecast that at other pressure. • Error of forecast method is 41.00% lower than original kinetics equation. Carbon capture, utilization and storage (CCUS) is an effective technology to reduce carbon dioxide (CO 2) content in atmosphere, while due to the insufficient mastery of deterioration laws of reservoir rocks caused by CO 2 , the extensive application of carbon storage projects is hindered by the leakage risk. Therefore, it was aimed to study the kinetics mechanism of pore water pressure on CO 2 -water–rock interactions. First, the pressure effect on water–rock interactions was studied to obtain the relationship between ratio of solid–liquid contact area Ψ and pore pressure, and the controlling mechanism of Ψ on reaction rate r i was verified. On this basis, the pressure effect on CO 2 -water–rock interactions was further studied. Considering the effects on Ψ and solution acidity, the original CO 2 -applicable kinetics equation was modified to reduce the error of calculating reaction rate by 33.60% on average. Meanwhile, a forecast method was proposed for the reaction rate under different pressure conditions, and the average calculation error was 41.00% lower than that of original kinetics equation. After verifying the accuracy of these two theoretical methods to calculate reaction rate, the reliability to calculate porosity evolution process was further verified, and the calculation errors could be reduced by 29.52% and 31.81%, respectively. [ABSTRACT FROM AUTHOR]

Large amounts of anthropogenic CO2 in the atmosphere are taken up when the ocean alters the seawater carbonate system, which could have a significant impact on carbonate-rich sediments. Coral reef limestone is a special biogenic carbonate, which is mainly composed of calcium carbonate. When carbonate-rich rocks are brought into contact with a CO2 weak acid solution, they will be dissolved, which may affect the physical and mechanical properties of the rock. In this paper, the physical and chemical interactions between CO2, seawater and the framework structure reef limestone were studied based on an experiment conducted in a hydrothermal reactor. The solution was analyzed for dissolved Ca2+ concentration during the reaction, and the rock mass, effective volume (except for the volume of open pores), permeability, images from electron microscopy and X-ray microtomography were contrasted before and after immersion. The uniaxial compressive and tensile strength tests were conducted, respectively, to clarify the mechanical response of the rock after the reaction. The results indicate that dissolution occurred during the reaction, and the calcium ions of the solution were increased. The physical properties of the rock were changed, and the permeability significantly increased. Because the rocks were soaked for only 15 days, the total cumulative amount of calcium carbonate dissolved was less, and the mechanical properties were not affected. [ABSTRACT FROM AUTHOR]

To investigate the impact of CO2 on rocks during the whole period of CO2 pre-pad energized fracturing operation for thin interbedded shale reservoir, including fracturing and well shut-in, a series of laboratory triaxial fracturing experiments and CO2 soaking experiments were conducted on thin interbedded shale (from Jimsar formations). In these experiments, combined with computed tomography (CT), the effect of fracturing fluid, horizontal principal stress difference, vertical principal stress, and natural fractures on fracture morphology were studied respectively. And based on X-ray diffraction (XRD) and scanning electron microscopy (SEM) experiments, the dissolution of minerals and the changes of pore structure before and after CO2 soaking were analyzed. The results of the fracturing experiment show that the bedding planes are easy to be opened by low viscosity of CO2 and the longitudinal fractures intersect with bedding planes to build a complex fracture network. During CO2 fracturing of thin interbedded shale, the horizontal principal stress difference is no longer a crucial factor to form a complex fracture network, but the vertical stress and natural fractures play important roles. And the soaking experiments indicate that the main dissolved mineral is carbonate whose dissolution ratio can reach 45.2% after soaking for 5 days, leading to the expansion of original pores or the exposure of new pores.

Supercritical carbon dioxide (SC-CO2) fracturing has been used in developing low permeability and water-sensitive reservoirs in recent years, which is expected to become a new generation of unconventional reservoir fracturing fluid. However, the water-rock interaction characteristics of various lithology shales under SC-CO2 circumstance and its influence on fracturing effect still need to be investigated. Two kinds of shale samples from C7 and S1 formations of the Ordos Basin were treated by SC-CO2 with formation water. The aims of the research are to determine the processes taking place in shale reservoir when considering minerals components transformation, porosity/permeability variation, and micro pore-structure change during the SC-CO2 fracturing. Static and dynamic SC-CO2 immersed experiments were conducted and the scanning of electron microscopy (SEM) and X-ray diffraction (XRD) was employed to analyze the surface morphology and newly formed minerals. Helium porosimeter, the ultralow permeability meter, and the CT scanner are employed to record the alternation of physical parameters during SC-CO2 dynamic injection. The experimental results show that the C7 samples are rich of chlorite and easily reacting with SC-CO2 saturated formation water to form new minerals, but the S1 samples are insensitive to aqueous SC-CO2. The minimum value of permeability and porosity of the C7 cores appear at 24h in the long-interval experiment, but in the short-interval dynamic experiment, the minimum values move ahead to 12h. The optimal flowback time for the C7 reservoir is before 12 h or after 24 h. The high-pressure SC-CO2 flooding pushes the new forming minerals particles to migrate to the outlet side and block the pore throat. For the S1 core results, the porosity and permeability change little in both short and long interval experiments. There is no strict flow-back time requirement for S1 reservoir during SC-CO2 fracturing. This study is significance for the efficient application of SC-CO2 in the exploitation of shale oil reservoirs.

Large amounts of anthropogenic CO2 in the atmosphere are taken up when the ocean alters the seawater carbonate system, which could have a significant impact on carbonate-rich sediments. Coral reef limestone is a special biogenic carbonate, which is mainly composed of calcium carbonate. When carbonate-rich rocks are brought into contact with a CO2 weak acid solution, they will be dissolved, which may affect the physical and mechanical properties of the rock. In this paper, the physical and chemical interactions between CO2, seawater and the framework structure reef limestone were studied based on an experiment conducted in a hydrothermal reactor. The solution was analyzed for dissolved Ca2+ concentration during the reaction, and the rock mass, effective volume (except for the volume of open pores), permeability, images from electron microscopy and X-ray microtomography were contrasted before and after immersion. The uniaxial compressive and tensile strength tests were conducted, respectively, to clarify the mechanical response of the rock after the reaction. The results indicate that dissolution occurred during the reaction, and the calcium ions of the solution were increased. The physical properties of the rock were changed, and the permeability significantly increased. Because the rocks were soaked for only 15 days, the total cumulative amount of calcium carbonate dissolved was less, and the mechanical properties were not affected.

Dawsonite commonly occurs in CO 2 -enriched strata and gas reservoirs, which is the product of CO 2 trapping or "mineral fixation". In this study, we focused on dawsonite and conducted series of experiments with three groups of variables: temperature (80/100/120/140 °C), pH (4/6/7/9), pCO 2 (0/4.3 Mpa) for comparison, aiming at understanding potential natural processes within CO 2 –H 2 O–dawsonite bearing sandstones systems. We conducted a series of studies on the alteration characteristics of dawsonite-bearing sandstones, evolutionary mode of fluid properties, alteration of dawsonite by fluid, and the mechanism of mineral precipitation and dissolution in closed systems. Based on Scanning Electron Microprobe (SEM) observation, energy spectrum analysis, X-ray diffraction analysis, and thermodynamic numerical simulation, we evaluated the influences of temperature, pH and pCO 2 on the stability of dawsonite preserved in sandstone, and further identified the favorable conditions for mineral trapping of CO 2. The hydrothermal experiments suggested that: for the temperature in the range of 80 °C–140 °C, the stability of dawsonite decreased with increasing temperature, and the fluid alteration influence on dawsonite mainly followed transformation path. When the pH is in range of 4–9, the stability of dawsonite decreased with the decreasing pH, and the alteration of dawsonite by fluid mainly followed decomposition path. pCO 2 decided the thermal stability of dawsonite, and when pCO 2 increased from 0 MPa to 4.3 MPa, the degree of dawsonite corrosion decreased and its stability increased. The results of hydrothermal experiment agree well with the thermodynamic numerical simulation, and indicate that the alkaline closed system with low temperature and high pCO 2 is ideal for "Carbon Capture and Storage", which can promote the formation and conservation of CO 2 "entrapment minerals", and benefit the long-term and stable geological CO 2 sequestration. • Establish the effects of temperature, pH, pCO 2 on the stability of dawsonite in sandstone. • Discuss the alteration paths of dawsonite by fluid. • Indicate the dissolution and precipitation mechanism of carbonates in various conditions. • Identify the ideal environment for the formation and conservation of CO 2 "entrapment minerals". [ABSTRACT FROM AUTHOR]

• This study evaluates the potential impact of leaking CO 2 gas and CO 2 -rich fluids on shallow groundwater quality. • The degree of CO 2 -water-rock interactions is an important parameter affecting the mobilization of trace elements. • The upwelling of deep CO 2 -rich fluids undergoing severe water-rock interactions can be harmful to shallow potable groundwaters. This study evaluates the potential impact of leaking CO 2 gas and CO 2 -rich waters on shallow groundwater quality by focusing on the mobilization of trace elements. For this study, Group I (acidic CO 2 -rich waters with low TDS), Group II (slightly acidic CO 2 -rich waters with high TDS), and Group III (CO 2 -poor waters with low TDS) were sampled in the study area occurring naturally CO 2 -rich waters. The carbon isotope data (δ13C and 14C) indicate that the dissolved CO 2 in CO 2 -rich water originates from old and deep-seated CO 2. Our results show that Group I is formed by the direct input of CO 2 gas into recently recharged shallow groundwater, whereas Group II discharging along fractures or wells occurs by long-term CO 2 -water-rock interactions in the subsurface. Group I shows higher concentrations of trace elements (Al, Ba, Be, Cr, Cs, Fe, Mn, Ni, Rb, and U) than Group III, and its Al and Mn concentrations slightly exceed the US EPA drinking water standard. However, Group II has significantly higher concentrations of trace elements than Group I. In particular, harmful Be exceeds the US EPA drinking water standard by over 6.5-fold. In addition, Fe and Mn exceed the US EPA drinking water standard by 27.7-fold and 16.1-fold, respectively. The higher concentration of bicarbonate by pH buffering in Group II also increases the mobilization of U6+. Our results show that the mobilization of trace elements in the aquifer having little buffering capacity is mainly determined by the degree of CO 2 -water-rock interactions. This study indicates that upwelling of deep CO 2 -rich fluids with long-term water-rock interactions can be harmful to shallow potable groundwaters by supplying high levels of trace elements into shallow aquifers. [ABSTRACT FROM AUTHOR]

Abstract Lake Nyos is a meromictic lake with strong stratification separated into 4 distinct layers; shallow, intermediate, transitional, and bottom layers. This article discusses enrichment of Fe2+ in the bottom water in January 2003 when the effect of artificial degassing that started in January 2001 on the chemical structure of the lake was still minimal. In the bottom layer (205.5–209.5 m), Fe2+ and HCO 3 − are the major dissolved species and their concentrations increase sharply toward the bottom. Enrichment of Fe2+ and HCO 3 − is most likely caused by anaerobic microbial reduction of Fe(OH) 3 precipitates at the water-sediment interface. The Fe(OH) 3 precipitates sank to the bottom after atmospheric oxidation of Fe2+ dispersed by the degassing pipe. Lateritic hematite may also participate in the reduction reaction. Production of Fe2+ and HCO 3 − significantly increases the alkalinity and electric conductivity of the bottom-most water and is responsible for a small rise of pH between 205 m and 209.5 m, the bottom. The other dissolved species, e.g., Na+, K+, Ca2+, Mg2+, SiO 2(aq) etc., result from the CO 2 -water-basalt interaction at low temperatures (25°∼30 °C) in the sub-lacustrine fluid reservoir that is believed to exist in the diatreme beneath the lake bottom, and they seep into the bottom layer. Highlights • High enrichment of Fe2+ and HCO3− in Lake Nyos bottom water. • This enrichment was caused by anaerobic microbial reduction of Fe(OH)3 at the water-sediment interface. [ABSTRACT FROM AUTHOR]

The CO2-rich spring water (CSW) occurring naturally in three provinces, Kangwon (KW), Chungbuk (CB), and Gyeongbuk (GB) of South Korea was classified based on its hydrochemical properties using compositional data analysis. Additionally, the geochemical evolution pathways of various CSW were simulated via equilibrium phase modeling (EPM) incorporated in the PHREEQC code. Most of the CSW in the study areas grouped into the Ca-HCO3 water type, but some samples from the KW area were classified as Na-HCO3 water. Interaction with anorthite is likely to be more important than interaction with carbonate minerals for the hydrochemical properties of the CSW in the three areas, indicating that the CSW originated from interactions among magmatic CO2, deep groundwater, and bedrock-forming minerals. Based on the simulation results of PHREEQC EPM, the formation temperatures of the CSW within each area were estimated as 77.8 and 150 °C for the Ca-HCO3 and Na-HCO3 types of CSW, respectively, in the KW area; 138.9 °C for the CB CSW; and 93.0 °C for the GB CSW. Additionally, the mixing ratios between simulated carbonate water and shallow groundwater were adjusted to 1:9-9:1 for the CSW of the GB area and the Ca-HCO3-type CSW of the KW area, indicating that these CSWs were more affected by carbonate water than by shallow groundwater. On the other hand, mixing ratios of 1:9-5:5 and 1:9-3:7 were found for the Na-HCO3-type CSW of the KW area and for the CSW of the CB area, respectively, suggesting a relatively small contribution of carbonate water to these CSWs. This study proposes a systematic, but relatively simple, methodology to simulate the formation of carbonate water in deep environments and the geochemical evolution of CSW. Moreover, the proposed methodology could be applied to predict the behavior of CO2 after its geological storage and to estimate the stability and security of geologically stored CO2. [ABSTRACT FROM AUTHOR]

• A kinetics equation is proposed to describe CO 2 -water–rock interactions. • Bridging by mass loss, a kinetics calculation method is proposed for pore evolution. • Rock porosity is dominantly controlled by soluble minerals in reaction process. • Reaction extent of soluble minerals is linearly correlated with porosity increment. • Dissolution of soluble minerals and rock pore evolution are weakened by flow effect. Carbon capture and storage (CCS) technology is an important measure to reduce carbon emissions, and the safety of CCS projects largely depends on the physical and chemical processes of CO 2 -water–rock interactions in reservoirs. As the important petrophysical parameters of reservoir rocks, the change trends of pore structure parameters are usually ignored and thus difficult to quantitatively master. In this study, non-flow and flow interaction tests were performed under the premise of considering the flow effect of liquid environment. Based on chemical kinetics method, the reaction kinetics equation was first established, and the different reaction mechanisms of soluble and insoluble minerals were clarified. In flow interactions, the dissolution of soluble minerals is weakened and the precipitation of insoluble minerals is enhanced. The evolution trends of pore structure parameters were further analysed to find the inhibited pore evolution process by flow effect. A kinetics method was proposed to calculate the pore evolution process. The dominantly controlling effect of soluble minerals on the pore evolution process was illustrated by correlation analysis, and a prediction method for porosity increment was proposed based on the reaction extent of soluble minerals. Eventually, the CO 2 -water–rock interaction mechanism was clarified from the mineral level. [ABSTRACT FROM AUTHOR]

The effects of CO2-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO2 in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO2. According to the experimental results, the values of UCS, Young's modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO2. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young's modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young's modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO2, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO2). SC-CO2 causes a greater reduction of shale's mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO2. The EDS results show that CO2-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation. [ABSTRACT FROM AUTHOR]

The effects of CO2-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO2 in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO2. According to the experimental results, the values of UCS, Young’s modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO2. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young’s modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young’s modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO2, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO2). SC-CO2 causes a greater reduction of shale’s mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO2. The EDS results show that CO2-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation.

Naturally outflowing CO2-rich springs are a natural analogue of the seepage of sequestered CO2 in geological storage sites. In Kangwon district of South Korea, two hydrochemically different types of CO2-rich springs (i.e., Ca-HCO3-type and Na-HCO3-type) occur together in a granitic terrain. Hydrochemical and water-isotope data (i.e., δ18O-δD and tritium) show that Na-HCO3-type springs have experienced significant silicate weathering processes over a long residence time at depths, while Ca-HCO3-type springs were formed by the mixing of Na-HCO3-type springs with shallow groundwater during ascent. In this study, diverse geochemical models including mixing, ion exchange and reaction path were investigated to verify the geochemical processes accounting for the occurrence of two contrasting types of CO2-rich springs. The mixing and ion exchange models reveal that Ca-HCO3-type springs are well explained by reverse cation exchange occurring during the mixing of Na-HCO3-type springs with shallow groundwater. The Na-HCO3-type springs are well explained by the reaction path modeling including the dissolution of silicate minerals (plagioclase, K-feldspar and biotite) and the precipitation of secondary minerals (calcite, kaolinite, muscovite and Mg-beidellite), implying that dissolved carbon is sequestered by calcite precipitation (i.e., mineral trapping). However, the concentrations of K in our modeling results are far below those of K observed in Na-HCO3-type springs, because of the precipitation of muscovite considered in the model, suggesting the partial disequilibrium state of the aquifer during the hydrolysis of K-feldspar under high PCO2 conditions. This result implies that to better predict long-term CO2-water-rock interactions in a geological storage site with abundant K-feldspar, the secondary K-bearing minerals should be carefully predicted, because a target aquifer can be far from chemical equilibrium during the storage period. This study shows that geochemical modeling can be effectively used to predict the hydrochemical changes of groundwater during long-term CO2-water-rock interactions and subsequent leakage toward surface in K-feldspar rich aquifer, although it should be included in a fully coupled computational approach between fluid flow, heat transfer and reactive mass transport processes in the future research. [ABSTRACT FROM AUTHOR]

Abstract: The peridotite section of the Samail Ophiolite in the Sultanate of Oman offers insight into the feasibility of mineral carbonation for engineered, in situ geological CO2 storage in mantle peridotites. Naturally occurring CO2 sequestration via mineral carbonation is well-developed in the peridotite; however, the natural process captures and sequesters CO2 too slowly to significantly impact the concentration of CO2 in the atmosphere. A reaction path model was developed to simulate in situ CO2 mineralization through carbonation of fresh peridotite, with its composition based on that of mantle peridotite in the Samail Ophiolite and including dissolution kinetics for primary minerals. The model employs a two-stage technique, beginning with an open system and progressing to three different closed system scenarios- a natural system at 30°C, an engineered CO2 injection scenario at 30°C, and an engineered CO2 injection scenario at 90°C. The natural system model reproduces measured aqueous solute concentrations in the target water, signifying the model is a close approximation of the natural process. Natural system model results suggest that the open system achieves steady state within a few decades, while the closed system may take up to 6,500years to reach observed fluid compositions. The model also identifies the supply of dissolved inorganic carbon as the limiting factor for natural CO2 mineralization in the deep subsurface. Engineered system models indicate that injecting CO2 at depth could enhance the rate of CO2 mineralization by a factor of over 16,000. CO2 injection could also increase mineralization efficiency – kilograms of CO2 sequestered per kilogram of peridotite – by a factor of over 350. These model estimates do not include the effects of precipitation kinetics or changes in permeability and reactive surface area due to secondary mineral precipitation. Nonetheless, the faster rate of mineralization in the CO2 injection models implies that enhanced in situ peridotite carbonation could be a significant sink for atmospheric CO2. [Copyright &y& Elsevier]

Abstract: One way to reduce the amount of CO2 in the atmosphere for the mitigation of climate change is to capture the CO2 and inject it into geological formations. The most important public concern about carbon capture and storage (CCS) is whether stored CO2 will leak into groundwater sources and finally into the atmosphere. To prevent the leakage, the possible leakage paths and the mechanisms triggering the paths must be examined and identified. It is known that the leakage paths can be due to CO2- rock interaction and CO2–well interaction. The objective of this research is to identify the geochemical reactions of the dissolved CO2 in the synthetic formation water with the rock minerals of the Sayindere cap rock by laboratory experiments. It is also aimed to model and simulate the experiments using ToughReact software. Sayindere formation is a regionally extensive cap rock for many oil fields in southeastern Turkey. The mineralogical investigation and fluid chemistry analysis of the experiments show that calcite was dissolved from the cap rock core as a result of CO2-water-rock interaction. Using the reactive transport code TOUGHREACT, the modeling of the dynamic experiment is performed. Calcite, the main primary mineral in the Sayindere is dissolved first and then re-precipitated during the simulation process. The decreases of 0.01% in the porosity and 0.03% in permeability of the packed core of the Sayindere cap rock are observed in the simulation. The simulation was continued for 25 years without CO2 injection. However, the results of this simulation show that the porosity and permeability are increased by 0.001% and 0.004%, respectively due to the CO2-water-rock mineral interaction. This shows that the Sayindere cap rock integrity must be monitored in the field if application is planned. [Copyright &y& Elsevier]

Abstract: To test the injection behaviour of CO2 into brine-saturated rock and to evaluate the dependence of geophysical properties on CO2 injection, flow and exposure experiments with brine and CO2 were performed on sandstone samples of the Stuttgart Formation representing potential reservoir rocks for CO2 storage. The sandstone samples studied are generally fine-grained with porosities between 17 and 32% and permeabilities between 1 and 100mD. Additional batch experiments were performed to predict the long-term behaviour of geological CO2 storage. Reservoir rock samples were exposed over a period of several months to CO2-saturated reservoir fluid in high-pressure vessels under in situ temperature and pressure conditions. Petrophysical parameters, porosity and the pore radius distribution were investigated before and after the experiments by NMR (Nuclear Magnetic Resonance) relaxation and mercury injection. Most of the NMR measurements of the tested samples showed a slight increase of porosity and a higher proportion of large pores. [ABSTRACT FROM AUTHOR]

Abstract: We investigated the nature and rates of in-situ CO2–fluid–rock reactions during an aqueous phase CO2 injection test. Two push–pull test experiments were performed at the Lamont–Doherty Earth Observatory test site (New York, USA): a non reactive control test without CO2 addition and a reactive test with CO2 equilibrated with the injected solution at a partial pressure of 1.105 Pa. The injected solution contained chemical and isotopic conservative tracers (NaCl and 18O) and was injected in an isolated and permeable interval at approximately 250 m depth. The injection interval was located at the contact zone between the Palisades sill (chilled dolerite) and the underlying metamorphic Newark Basin sediments and the injected solution incubated within this interval for roughly 3 weeks. Physico-chemical parameters were measured on the surface (pH, temperature, electrical conductivity) and water samples were collected for chemical (Dissolved Inorganic Carbon — DIC, major ions) as well as for isotopic (δ 13CDIC, δ 18O) analyses. For the control test, post-injection chemical and isotopic compositions of recovered water samples display mixing between the background water and the injected solution. For the reactive CO2 test, observed δ 13CDIC and DIC both increase, and enrichment in Ca2+, Mg2+, K+ allow for quantification of the chemical pathways through which aqueous CO2 and subsequent H2CO3 were converted into HCO3 −. Dissolution of carbonate minerals was the dominant H2CO3 neutralization process (≈52±7%), followed by cation exchange and/or dissolution of silicate minerals (≈45±10%, for both processes), and to a minor extent, mixing of the injected solution with the formation water (≈3±1%). The results confirm the rapid dissolution kinetics of carbonate minerals compared to those of basic silicate minerals. However, our results remain marked by uncertainties due to the natural variability of the background water composition, in mass balance calculations. These experiments imply that the use of accurate DIC measurements can quantify the relative contribution of CO2–fluid–rock reactions and evaluate the geochemical trapping potential for CO2 storage in reactive reservoir environments. [Copyright &y& Elsevier]

• Benchmark for geochemical modeling in PHREEQC, TOUGHREACT, and GEM simulators. • A method to minimize discrepancies in the modeling of CO2-water-rock interactions. • Thermodynamic database consistency and accurate fluid properties calculation. • Workflow for batch reaction and 1D reactive transport cases. The capabilities of reactive transport modeling codes for geological carbon sequestration have improved significantly in the past decade. Comparing different geochemical modeling codes is crucial to identify modeling discrepancies, especially when experimental validation is not feasible. However, it is challenging to consistently get comparable results, as shown in previous studies where batch reaction of CO 2 storage using different simulators sometimes resulted in significant discrepancies in their outputs. In this study, we introduce and demonstrate an approach to consistently produce comparable batch-reaction modeling of kinetically controlled CO 2 -water-rock interactions in PHREEQC, TOUGHREACT, and GEM, which are amongst the most widely used simulators for CO 2 sequestration studies. The primary step is to assemble a thermodynamic database in PHREEQC format, with representative fluid properties for CO 2 -water interaction, and carefully convert it to the format of the other simulators. We use two case studies from the literature to demonstrate our method where good matches between the outputs of all three simulators were achieved, which was not previously attained. Furthermore, limiting the discrepancies in batch-reaction models provides a consistent baseline to study the coupled mechanisms of transport and chemical reaction, which was also successfully demonstrated with a one-dimensional reactive transport model in PHREEQC, GEM and TOUGHREACT. [ABSTRACT FROM AUTHOR]

CO2 geological storage is considered as an important measure to reduce anthropogenic CO2 emissions to the atmosphere for addressing climate change. The key prerequisite for long-term CO2 geological storage is the sealing capacity of caprock. This study investigates the evolution of sealing capacity of caprock induced by geochemical reactions among CO2, water and caprock using TOUGHREACT code based on the Heshanggou Formation mudstone at the Shenhua Carbon Capture and Storage (CCS) demonstration site of China. The results show that the self-sealing phenomenon occurs in the lower part of the caprock dominated by the precipitation of dawsonite, magnesite, siderite, Ca-smectite and illite. While the self-dissolution occurs in the upper part of caprock mainly due to the dissolution of kaolinite, K-feldspar, chlorite and Ca-smectite. Sensitivity analyses indicate that the precipitation of dawsonite, magnesite, siderite is highly advantageous leading to self-sealing of caprock, with albite and chlorite dissolution providing Na+, Mg2+ and Fe2+. The dissolution of K-feldspar dominates illite precipitation by providing required K+, and albite affects Ca-smectite precipitation. The self-sealing and self-dissolution of caprock are enhanced significantly with increasing temperature, while the effect of salinity on caprock sealing capacity is negligible perhaps due to the low salinity level of formation water. [ABSTRACT FROM AUTHOR]

The effects of CO₂-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO₂ in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO₂. According to the experimental results, the values of UCS, Young's modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO₂. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young's modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young's modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO₂, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO₂). SC-CO₂ causes a greater reduction of shale's mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO₂. The EDS results show that CO₂-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation.