Solubility Trapping Research Articles

Hydrogeochemical numerical simulation of impacts of mineralogical compositions and convective fluid flow on trapping mechanisms and efficiency of carbon dioxide injected into deep saline sandstone aquifers

A series of numerical simulations, which consider density‐dependent (convective) groundwater and carbon dioxide (CO2) flow, is performed using a multiphase hydrogeochemical reactive transport numerical model to evaluate impacts of mineralogical compositions on the trapping mechanisms and efficiency of CO2 injected into a deep saline sandstone aquifer (reservoir rock). The results of the numerical simulations show that the mineralogical compositions of the sandstone aquifer have significant impacts on hydrogeochemical behavior of injected CO2 and thus its trapping mechanisms and efficiency. Injected CO2 is accumulated as a free fluid phase beneath the caprock (i.e., hydrodynamic trapping), then dissolved as aqueous phases such as bicarbonate and carbonate anions into groundwater (i.e., solubility trapping), and finally precipitated as carbonate minerals (i.e., mineral trapping). Mineral trapping of injected CO2 takes places as precipitation of a primary carbonate mineral such as calcite and secondary carbonate minerals such as dawsonite, siderite, ankerite, and magnesite. The patterns of hydrogeochemical reactions depend significantly on the initial presence and absence of chlorite in the sandstone aquifer. For mineral trapping of injected CO2, ankerite is the most dominant mineral when chlorite is initially present, whereas dawsonite is the most dominant mineral when chlorite is initially absent in the sandstone aquifer. Mg2+ and Fe2+, which are essential chemical components of such secondary carbonate minerals (i.e., siderite, ankerite, and magnesite) for mineral trapping of injected CO2, are mainly supplied by dissolution of chlorite. As a result, the precipitation amounts of the secondary carbonate minerals and thus the efficiency of mineral trapping of injected CO2 increase significantly as the volume fraction of chlorite increases in the sandstone aquifer. A series of additional numerical simulations, which consider density‐independent (non‐convective) multiphase fluid flow, is also performed using the same numerical model, and then its results are compared with those of the above‐mentioned numerical simulations, which consider density‐dependent (convective) multiphase fluid flow, to evaluate impacts of convective fluid flow on the trapping mechanisms and efficiency of injected CO2. The comparison of the results of both numerical simulations shows that convective fluid flow also has significant impacts on hydrogeochemical behavior of injected CO2 and thus its trapping mechanisms and efficiency. Convective fluid flow reduces the free fluid phase of CO2 (i.e., hydrodynamic trapping) and thus enhances the aqueous and solid phases of CO2 (i.e., initially solubility trapping and then mineral trapping).

Aquifer Management To Accelerate CO2 Dissolution and Trapping

Summary Bulk-phase CO2 injection into saline aquifers can provide substantive reduction in CO2 emissions if the risk arising from aquifer pressurization is addressed adequately through mechanisms such as brine production out of the system (Anchliya 2009). While this approach addresses the risks associated with aquifer pressurization it does not address the problem of ensuring CO2 trapping as an immobile phase and its accumulation at the top of the aquifer. The performance of bulk-CO2-injection schemes highly depends on the seal-integrity assessment and presence of thief zones. The accumulated pocket of free CO2 can readily leak through a breach in the aquifer seal. Ideally, the aquifer should be monitored as long as the free CO2 is present, but if the CO2 is not immobilized, it is expected to remain underneath the seal rock for more than 1,000 years. Therefore, long-term monitoring of the seal integrity and avoiding leakage will be very costly. To minimize the free CO2 below the caprock, we propose an engineered system to reduce aquifer pressurization and accelerate CO2 dissolution and trapping. We achieve these objectives through effective placement of brine injection and production wells to facilitate the lateral movement (hence, residual and solubility trapping) of CO2 in the aquifer and impede its upward movement. The simulation results for example engineered well configurations in this paper suggest that substantial improvements in immobilizing CO2 can be achieved through increasing enhanced solubility and residual trapping that result from better CO2-injection sweep efficiency. This approach has the potential to greatly reduce the risk of CO2 leakage both during and after injection. The controlled injection of CO2 with this technique reduces the uncertainty about the long-term fate of the injected CO2, prevents CO2 from migrating toward potential outlets or sensitive areas, and increases the volume of CO2 that can be stored in a closed aquifer volume during the CO2-injection period. Field-scale compositional simulation cases are discussed, and sensitivity studies are used to provide guidelines for well spacing and flow rates depending on aquifer properties and the volume of CO2 to be stored. Although it requires additional drilled wells, the active engineered configuration proposed for CO2 injection significantly reduces the reservoir volume required to effectively sequester a given volume of CO2, and the increase in the cost caused by additional wells is recovered by dramatic reduction in monitoring cost.

Geochemical modeling of CO2 sequestration in deep, saline, dolomitic-limestone aquifers: Critical evaluation of thermodynamic sub-models

Geochemical modeling is a common tool to estimate the potential for storing supercritical CO2 in deep saline aquifers, and to predict the effects thereof. Geochemical models necessarily rely on thermodynamic relationships or “sub-models” to estimate quantities such as chemical solubility, activity, and fugacity. In this paper, we compare three proposed models for the fugacity of supercritical CO2, four proposed models for the activity coefficient of dissolved (aqueous) CO2, and four proposed models for the solubility of CO2 in aquifer brine. We examine the conditions under which estimates from these different proposed thermodynamic sub-models agree or disagree. Also, we develop a geochemical model that predicts the effects of injecting CO2 into a deep, saline, dolomitic-limestone aquifer; specifically, we predict the change in brine pH, the mineral precipitation/dissolution, and the potential solubility trapping of injected CO2 in response to the CO2 injection. We test nine different versions of the model, utilizing different combinations of the thermodynamic sub-models listed above. This allows us to quantify how key geochemical predictions depend upon the selection of thermodynamic sub-models. We find that different combinations of thermodynamic sub-models yield similar estimates for equilibrium pH and for quantities of mineral precipitation/dissolution, but that agreement is worse when predicting the equilibrium CO2 concentration in brine and/or the solubility trapping of CO2. These results indicate that the predicted equilibrium pH and mineral precipitation/dissolution are not very sensitive to the underlying thermodynamic sub-models, whereas estimates for the CO2 concentration in brine and potential solubility trapping are. Overall, the geochemical predictions are least sensitive to the choice of CO2 activity coefficient sub-model, are moderately sensitive to the choice of CO2 solubility sub-model, and are most sensitive to the choice of CO2 fugacity coefficient sub-model.

CO2 migration in saline aquifers. Part 2. Capillary and solubility trapping

AbstractThe large-scale injection of carbon dioxide (CO2) into saline aquifers is a promising tool for reducing atmospheric CO2 emissions to mitigate climate change. An accurate assessment of the post-injection migration and trapping of the buoyant plume of CO2 is essential for estimates of storage capacity and security, but these physical processes are not fully understood. In Part 1 of this series, we presented a complete solution to a theoretical model for the migration and capillary trapping of a plume of CO2 in a confined, sloping aquifer with a natural groundwater through-flow. Here, we incorporate solubility trapping, where CO2 from the buoyant plume dissolves into the ambient brine via convective mixing. We develop semi-analytical solutions to the model in two limiting cases: when the water beneath the plume saturates with dissolved CO2 very slowly or very quickly (‘instantaneously’) relative to plume motion. We show that solubility trapping can greatly slow the speed at which the plume advances, and we derive an explicit analytical expression for the position of the nose of the plume as a function of time. We then study the competition between capillary and solubility trapping, and the impact of solubility trapping on the storage efficiency, a macroscopic measure of plume migration. We show that solubility trapping can increase the storage efficiency by several-fold, even when the fraction of CO2 trapped by solubility trapping is small.

CO 2 mineral sequestration mechanisms and capacity of saline aquifers of the Upper Silesian Coal Basin (Central Europe) - Modeling and experimental verification

Significant part of CO 2 emissions from industrial sources in Central Europe originates from the territory of the Upper Silesian Coal Basin (USCB). This paper presents a study of the suitability of saline aquifers within the USCB, as potential greenhouse gas repositories. Evaluation of mineral-trapping mechanisms and assessment of storage capacity of the aquifers is based on hydrochemical modeling and experimental tests of rock–water–gas interactions. Two stages of modeling enabled prediction of the immediate changes in the aquifer and insulating rocks impacted by the beginning of CO 2 injection, and the assessment of long-term effects of sequestration. In the analyzed sandstone aquifers the minerals able to trap CO 2 are dawsonite and dolomite, while siderite or calcite are able to degrade. The phases capable of mineral CO 2 trapping in the cap rocks are: dawsonite, dolomite, and siderite. Mineral-trapping capacity, for the sandstone aquifers is relatively low: 1.2 to 1.9 kgCO 2/m 3, with the exception of the Upper Silesian Sandstone Series – over 6.6 kgCO 2/m 3. The solubility trapping capacity does not exceed 4.07 kgCO 2/m 3.

Displacement and mass transfer between saturated and unsaturated CO2–brine systems in sandstone

AbstractThe process of displacement and mass transfer between CO2 and brine, which are relevant for the prediction of plume migration and pore-space utilization during CO2 injection in saline aquifers, were studied by conducting unsteady-state core flood experiments in nearly homogeneous Berea sandstone rock. Mutually saturated and unsaturated CO2 and brine phases were injected in the rock under realistic sequestration conditions.Relative permeability and capillary pressure curves were extracted by history matching the unsteady state experiments conducted with mutually saturated CO2 and brine. As a reference and for comparison, decane–brine primary drainage was conducted on the same sample. The CO2–brine relative permeability was found to be different from the decane–brine relative permeability (which had been validated against steady-state experiments on twin-samples), reflecting the change in the wetting state from water-wet decane–brine/Berea to the rather intermediate-wet behavior of CO2–brine/Berea, which is in agreement with literature data on contact-angles for the two cases. However, the CO2 brine data are somewhat different from data on the same rock type as reported by Perrin and Benson (2010) which is likely a consequence of sample heterogeneity.Aspects of the mass transfer between the CO2 and the brine phase were studied by drainage and imbibition with unsaturated phases. When comparing saturated and unsaturated CO2–brine primary drainage, the mass transfer due to mutual solubility leads to two effects: (1) evaporation near the inlet due to water dissolving in CO2 and (2) a diminished displacement of brine by CO2 due to CO2 dissolving in brine. In addition, an imbibition experiment was conducted where unsaturated brine was injected into rock filled with mutually saturated CO2 and brine phase at near-residual CO2 saturation. After the CO2-saturated brine had been miscibly displaced by unsaturated brine, dissolution of the trapped CO2 in the injected brine was subsequently observed. These experiments represent the transition from residual trapping to solubility trapping and indicate the time and length scales involved.

Vertically averaged approaches for CO2 migration with solubility trapping

The long‐term storage security of injected carbon dioxide (CO2) is an essential component of geological carbon sequestration operations. In the postinjection phase, the mobile CO2 plume migrates in large part because of buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over hundreds to thousands of years and can immobilize a significant portion of the mobile CO2 plume. However, both the migration and trapping processes are inherently complex, spanning multiple spatial and temporal scales. Using an appropriate model that can capture both large‐ and small‐scale effects is essential for understanding the role of these processes on the long‐term storage security of CO2 sequestration operations. Traditional numerical models quickly become prohibitively expensive for the type of large‐scale, long‐term modeling that is necessary for characterizing the migration and immobilization of CO2 during the postinjection period. We present an alternative modeling option that combines vertically integrated governing equations with an upscaled representation of the dissolution‐convection process. With this approach, we demonstrate the effect of different modeling choices for typical large‐scale geological systems and show that practical calculations can be performed at the temporal and spatial scales of interest.

Dimerization of Soluble Disulfide Trap Single-Chain Major Histocompatibility Complex Class I Molecules Dependent on Peptide Binding Affinity

Stable presentation of peptide epitope by major histocompatibility complex (MHC) class I molecules is a prerequisite for the efficient expansion of CD8(+) T cells. The construction of single-chain MHC class I molecules in which the peptide, β(2)-microglobulin, and MHC heavy chain are all joined together via flexible linkers increases peptide-MHC stability. We have expressed two T cell epitopes that may be useful in leukemia treatment as single-chain MHC class I molecules, aiming to develop a system for the expansion of antigen-specific CD8(+) T cells in vitro. Disulfide trap versions of these single-chain MHC molecules were also created to improve anchoring of the peptides in the MHC molecule. Unexpectedly, we observed that soluble disulfide trap single-chain molecules expressed in eukaryotic cells were prone to homodimerization, depending on the binding affinity of the peptide epitope. The dimers were remarkably stable and efficiently recognized by conformation-specific antibodies, suggesting that they consisted of largely correctly folded molecules. However, dimerization was not observed when the disulfide trap molecules were expressed as full-length, transmembrane-anchored molecules. Our results further emphasize the importance of peptide binding affinity for the efficient folding of MHC class I molecules.

Probability Density Function Modeling of Multi-Phase Flow in Porous Media with Density-Driven Gravity Currents

A probability density function (PDF) based approach is employed to model multi-phase flow with interfacial mass transfer (dissolution) in porous media. The joint flow statistics is represented by a mass density function (MDF), which is transported in the physical and probability spaces via Fokker–Planck equation. This MDF-equation requires Lagrangian evolutions of the random flow variables; these evolutions are stochastic processes honoring the micro-scale flow physics. To demonstrate the concept, we consider an example of immiscible two-phase flow with the non-equilibrium dissolution of single component from one phase into the other-a model for solubility trapping during CO2 storage in brine aquifer. Since CO2-rich brine is denser than pure brine, density-driven countercurrent flow is set up in the brine phase. The stochastic models mimicking the physics of countercurrent flow lead to a modeled MDF-equation, which is solved using our recently developed stochastic particle method for multi-phase flow (Tyagi et al. J Comput Phys 227:6696–6714, 2008). In addition, we derive Eulerian equations for stochastic moments (mean, variance, etc.) and show that unlike the MDF-equation the system of moment equations is not closed. In classical Darcy formulation, for example, the mean concentration equation is closed by neglecting variance. However, with several one- and two-dimensional simulations, it is demonstrated that the PDF and Darcy modeling approaches give significantly different results. While the PDF-approach properly accounts for the long correlation length scales and the concentration variance in density-driven countercurrent flow, the same phenomenon cannot be captured accurately with a standard Darcy model.

Using oxygen isotope ratios to quantitatively assess trapping mechanisms during CO 2 injection into geological reservoirs: The Pembina case study

Carbon Capture and Storage (CCS) is considered a viable option for reducing CO 2 emissions into the atmosphere from point sources such as coal-fired power plants. Monitoring of CO 2 storage sites is widely considered necessary for safety reasons and for verification of injected CO 2 in the reservoir. The latter is crucially dependent on the ability to determine CO 2 trapping mechanisms and to assess pore-space saturation of CO 2. Thus far, attempts to determine CO 2 pore-space saturations at CO 2 injection sites have had limited success. Here, we present data from the Pembina Cardium CO 2 Monitoring Project in Alberta, Canada, that demonstrate that changes in the oxygen isotope ratios (δ 18O) of reservoir water can be indicative of the extent of pore-space saturation with CO 2. The δ 18O value of injected CO 2 at the injection site was + 28.6‰ (V-SMOW) and δ 18O values of reservoir water at eight observation wells varied between − 13.5 and − 17.1‰ (V-SMOW) before CO 2 injection. After commencement of CO 2 injection the δ 18O values of reservoir water at three observation wells increased between 1.1 and 3.9‰ due to the presence of large quantities of injected CO 2 and equilibrium isotope exchange between water and CO 2. Our calculations revealed that reservoir water fully saturated with CO 2 would only result in increases of δ 18O H2O values of 0.4‰. Hence the observed larger increases in δ 18O values of reservoir water indicate free phase CO 2 with estimated pore-space saturations ranging from 12% (corresponding to a δ 18O increase of 1.1‰) to 64% (δ 18O increase 3.9‰) of the non-oil saturated pore-space. Contributions to oxygen in the system from mineral dissolution were calculated to be less than 0.01% of total oxygen and therefore did not alter the δ 18O value of the reservoir water significantly. Hence we conclude that changes in the δ 18O values of reservoir water caused by the presence of injected CO 2 can be used as a tracer for CO 2 plume migration in the subsurface provided that the injected CO 2 is isotopically distinct. Furthermore, we submit that the extent of the changes in the δ 18O values of the reservoir water provides a quantitative assessment of CO 2 stored in dissolved form (solubility trapping), assuming no density driven convective overturn, and as free-phase CO 2 (structural, stratigraphic and hydrodynamic trapping) thereby elucidating the trapping mechanisms within the reservoir.

The impact of local-scale processes on large-scale CO2 migration and immobilization

Abstract Storage security of injected carbon dioxide (CO 2 ) is an essential component of risk management for geological carbon sequestration operations. During the injection and early post-injection periods, CO 2 leakage may occur along faults and leaky wells, but this risk may be partly managed by proper site selection and sensible deployment of monitoring and remediation technologies. On the other hand, long-term storage security is an entirely different risk management problem—one that is dominated by a mobile CO 2 plume that may travel over very large spatial distances, over long time periods, before it is trapped by a variety of different physical and chemical processes. In the post-injection phase, the mobile CO 2 plume migrates in large part due to buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over thousands to tens of thousands of years and can immobilize a significant portion of the mobile, free-phase CO 2 plume. However, both the migration and trapping processes are inherently complex, involving a combination of small and large spatial scales and acting over a range of time scales. Solubility trapping is a prime example of this complexity, where small-scale density instabilities in the dissolved CO 2 region leads to convective mixing that has that has a significant effect on the large-scale dissolution process over very long time scales. Another example is the effect of capillary forces on the evolution of mobile CO 2 , an often-neglected process except with regard to residual trapping. As the plume migrates due to buoyancy and viscous forces, local capillary effects acting at the CO 2 -brine interface lead to a transition zone where both fluids are present in the mobile state. This small-scale effect may have a significant impact on large-scale plume migration as well as long-term residual and dissolution trapping. Using appropriate models that can capture both large and small-scale effects is essential for understanding the role of these processes on the long-term storage security of CO 2 sequestration operations. There are several approaches to modeling long-term CO 2 trapping mechanisms. One modeling option is the use of traditional numerical methods, which are often highly sophisticated models that can handle multiple complex phenomena with high levels of accuracy. However, these complex models quickly become prohibitively expensive for the type of large-scale, long-term modeling that is necessary for risk assessment applications such as the late post-injection period. We present an alternative modeling option that combines vertically-averaged governing equations with an upscaled representation of the dissolution-convective mixing process and the local capillary transition zone at the CO 2 -brine interface. CO 2 injection is solved numerically on a coarse grid, capturing the large-scale injection problem and the post-injection capillary trapping, while the upscaled dissolution and capillary fringe models capture these subscale effects and eliminate the need for expensive grid refinement to capture the subscale instabilities associated with convective mixing or the details of the capillary transition zone. With this modeling approach, we demonstrate the effect of different modeling choices associated with dissolution and capillary processes for typical large-scale geological systems

Natural CO2 occurrence in geological formations and the implications on CO2 storage capacity and site selection

Abstract Accurate assessment of natural CO2 occurrence and its saturation state with respect to the mineral buffering effect could better guide CO2 storage site selection, injection performance and capacity estimation. The primary control on naturally occurring CO2 in the Earth’s crust results from its origin: Mantle and magmatic sources, thermal decomposition of carbonate minerals, thermal maturation of organic matter, thermochemical sulfate reduction, and bacterial activity. The concentration and distribution of the generated CO2 is further controlled by the migration processes and trapping mechanisms, and eventually, buffered by mineral-gas-fluid interactions. We investigated the controls on natural occurring CO2, including its concentration and distribution as a function of key geological variables, such as temperature, pressure, mineralogy, and fluid chemistry. An example from Mobile Bay (e.g., ), is compared with other field studies including Gulf Coast reservoirs and geothermal areas from Iceland. We coupled CO2 thermodynamic modeling with the field data to describe the geological controls on CO2 occurrence, and refined a theoretical correlation for estimating CO2 concentrations in geological formations. The primary observation used for estimating CO2 volumetrics is that the partial pressure of CO2 (p CO2) covaries with temperature, while the reservoir mineralogy plays a significant role in determining the p CO2–T correlation. This trend can be related to pH buffering associated with aluminosilicate and carbonate minerals and pore water interactions based on fundamental thermodynamic principles. The theoretical correlation matches the field data reasonably well, and should apply to a wide range of CO2 concentrations for reservoirs with constrained access to CO2 rich fluids. We applied state of the art CO2 injection reactive transport modeling (RTM) to investigate how natural occurring CO2 concentration and buffering state affect CO2 injection performance and capacity. Our RTM simulates large-scale CO2 injection into subsurface reservoirs, with the ability to capture the complex interplay of multiphase flow, capillary trapping, diffusion, convection, and chemical reactions, that may have significant impacts on both injection performance and storage security. The simulation results suggest that reservoirs with initial CO2 concentration below the buffering capacity tend to facilitate CO2 storage by increasing the structural, residual and solubility trapping. The under saturation conditions also help to avoid potential mineral precipitation and formation damage near the injection well and therefore, is a better choice for CO2 storage over reservoirs with initial CO2 exceeding the buffering capacity. We plan to investigate CO2 injections in different types of siliciclastic and carbonate reservoirs. This study expanded our fundamental understanding of CO2 occurrence, buffering and sequestration processes at multiple spatial and temporal scales in nature. The results helped us make better judgments of CO2 storage capacity and site selection that led to better design decisions from appraisal to development to monitoring.

Adsorption and mineral trapping dominate CO2 storage in coal systems

High-CO2 coal seams occur in many sedimentary basins world-wide and provide natural analogues of the processes likely to occur as a result of CO2 injection and storage in coal systems. CO2 is stored in coal predominantly as adsorbed molecules on micropore surfaces (adsorption trapping) that allow higher densities and greater volumes of CO2 at shallower depths than in sandstone and carbonate reservoirs. In the longer term CO2 will dissolve in formation water and react with minerals in the host formation (solubility/ionic trapping) and may be precipitated as carbonate minerals (mineral trapping). A recent study suggests that solubility trapping is the predominant CO2 sink in natural gas fields (Gilfillan et al., 2009), whereas our natural analogue studies in the Bowen and Gunnedah Basins, eastern Australia, indicate that CO2 has been stored in coal and sandstone formations since the Mesozoic through a combination of adsorption and mineral carbonation reactions. These differences reflect the different mineralogies and hydrogeology of the CO2-rich natural gas fields studied by Gilfillan et al. (2009) and coal systems. Our work shows that natural analogue studies of sites that have stored CO2 over geological time scales are essential to determine the mechanisms of CO2 storage and the level of characterisation required for storage site equivalents. (C) 2011 Published by Elsevier Ltd.

Numerical modeling of CO2 mineralisation during storage in deep saline aquifers

Simulations are performed to evaluate the feasibility of a potential site within the Rotliegend sandstone formation in the Dutch subsurface at a depth of around 3000 m for CO2 sequestration using the numerical simulator CMG-GEM. Three CO2 storage trapping mechanisms are studied: (1) mobility trapping, (2) solubility trapping, and (3) mineral trapping. Results show that the injected CO2 initially migrates towards the top of the reservoir due to gravity segregation. Then the CO2 spreads laterally and dissolves in the formation water (brine). Due to the dissolution of CO2 the density of the brine increases, which then results in fingering due to gravity. Further, the effect of mineralisation is included in the simulation. It is found in this study that considerable amounts of CO2 are stored mainly by solubility and mobile trapping. The contribution of mineral trapping is insignificant. Additionally, the effect of varying the permeability and the residual gas saturation on the CO2 storage-capacities are studied. It is found that a random permeability field enhances CO2 capturing by means of solubility trapping, while a higher residual gas saturation enhances the CO2 storage by means of mobility trapping.

Optimization of well placement for geological sequestration of carbon dioxide using adaptive evolutionary Monte Carlo algorithm

Abstract In the geological sequestration of CO 2 , the larger contribution of the secondary trappings, such as residual gas and solubility trappings, to CO 2 retention in the reservoir is preferred from a standpoint of the storage security. When we consider CO 2 injection into a specific storage site, only a few factors are controllable for us and among them is the well placement. Due to the heterogeneity and structure of the reservoir, CO 2 migration might be altered by the well placement and the optimum well placement can increase the contribution of the secondary trapping mechanisms. Thus, we consider the optimization of well placement in this study. The evolutionary Monte Carlo with kriging is used as a heuristic optimization technique, referred to as an adaptive evolutionary Monte Carlo (AEMC) algorithm. Objective function to be maximized is the amount of CO 2 trapped by the secondary mechanisms in the target area, while the independent variables are the grid indices of the injection well. By comparing with the exhaustive simulation, the efficiency of the AEMC algorithm is demonstrated.

Concept and experimental study for a new enhanced mineral trapping system by means of microbially mediated processes

The effectiveness of CO2 geological storage depends on a combination of physical and geochemical trapping mechanisms. Over time, the physical process of residual CO2 trapping and geochemical processes of solubility trapping and mineral trapping increase. According to the IPCC special report, mineral trapping is believed to be comparatively slow, potentially taking a thousand years or longer. This paper proposes a concept of enhanced mineral trapping system of CO2 geological storage by means of microbially mediated processes and describes some results of related preliminary microbial experiments. Environmental microorganisms have influences on groundwater chemistry and mineral precipitation and dissolution, and even accelerate mineral precipitation processes. The research objective is to accelerate mineral trapping by microbial activities. Especially, biomineralization of carbonate minerals acts an important role for the enhanced mineral trapping system. It is expected to reduce the time scale of mineral trapping from several thousand years to several decades (human life time). It is also expected to play a role for sealing capability. The goal of the research project is to extract optimum bacteria to form carbonate-forming habitats and to evaluate the possibility of bacteria-enhanced CO2 geological storage using numerical model. To develop the system, we plan to carry out the following four procedures; (1) looking for various kinds of carbonate-forming bacteria from natural samples, (2) extraction of bacteria for the condition of the system and further extraction of the bacteria with optimum performance of carbonate precipitation by laboratory experiments, (3) measurement the microbial kinetic parameters, such as specific growth rate of the bacteria by some laboratory experiments (4) performance assessment by hydro-bio-geochemical modeling using experimental data including microbial kinetic parameters. According to the research plan, we carried out literature investigation to make an inventory and preliminary laboratory experiments as the first step of looking for the optimum bacteria. Our target is biomineralization by moderately halophilic carbonate-forming bacteria, which few researchers have studied yet. Screenings of bacteria consists mainly of three steps as follows: 1) purchase of moderately halophilic bacteria, some of which are known carbonate-forming species, 2) selection of carbonate-formers from the isolated halophiles, and 3) selection of practically applicable carbonate-formers with higher performances. Preliminary batch culture experiments were performed with purchased different 6 species of moderately halophilic bacteria; Chromohalobacter marismortui, Halobacillus trueperi, Halomonas halophila, Marinobacter hydrocarbonoclasticus, Marinococcus halophilus, and Virgibacillus salexigens. Initial concentration of Ca2+ was set between 2.60 g/l and 2.75 g/l in the liquid cultures. Gradual decrease in Ca2+ concentration was observed for all microbial samples. After 98 days, Ca2+ concentration in the liquid culture of Mb. hydrocarbonoclasticus was 0.440 g/l. Ca2+ concentration of C. marismortui was 0.448 g/l after 189 days. Decrease in Ca2+ concentration was also observed for other 4 microbial species, although its degree and decreasing rate varied among species. Meanwhile, decrease in Ca2+ concentration was not observed in abiotic liquid culture. Chemical analysis by EPMA was also carried out for some microbes after the incubation, and higher peak of calcium, oxygen, carbon and minor magnesium were detected. These results indicate that the decrease in Ca2+ concentration was caused by microbial carbonate precipitation.

Effects of impurities on CO2 transport, injection and storage

Abstract Effects of impurities in CO 2 streams on geological storage of CO 2 have been investigated. A number of key issues have been addressed, and several significant findings have been made. Highlighted among the findings are: (1) non-condensable impurites such as N 2 , O 2 and Ar greatly reduce CO 2 storage capacity of geological formations, and there is a maximum reduction of the storage capacity at a certain pressure under a given temperature. By contrast, impurities which are more condensable than CO 2 , such as SO 2 , can increase the storage capacity, and there is a maximum increase at a certain pressure under a given temperature; (2) change of density caused by non-condensable gas impurities results in lower injectivity of impure CO 2 into geological formations. However, above a threshold pressure range the injectivity could reach the level of pure CO 2 due to lowered viscosity; (3) non-condensable impurities increase the buoyancy of the CO 2 plume. This would negatively affect the efficiency of solubility trapping and residual trapping of CO 2 . (4) the effect of SO 2 on reduction of rock porosity and hence CO 2 injectivity would be much smaller than previously thought. A simple formula has been developed to enable quick determination of the effect.

Enhanced solubility trapping of CO2 in fractured reservoirs

Abstract The dissolution of supercritical CO2 in formation water is one of the main trapping mechanisms for CO2 storage in saline aquifers. We develop an analytical solution for one-dimensional flow of CO2 in a fracture with dissolution into the surrounding matrix. The solute in the matrix is transported perpendicular to the fracture by molecular diffusion. We show that there is a time-scale when the mass transfer from dissolution and advection in the fractures is comparable - after this, there is significant dissolution of the injected CO2 and the transport through the fracture is slowed down. This time-scale is typically of order 1 day, implying that dissolution is significant for CO2 injection into fractured aquifers. This analysis suggests that dissolution may be a significant long-term trapping mechanism for fractured reservoirs. Although the reservoir volumes into which the CO2 must be injected will be huge, the CO2 will rapidly dissolve and hence is stored safely. We conclude by discussing dissolution as a potential permanent storage mechanism in fractured aquifers and the design of CO2 injection in such systems. We compare analytical and numerical solutions for a single fracture. The numerical solution also accommodates transport of the solute in the fracture plane and confirms that the analytical analysis is a very close approximation of the full three-dimensional problem for simple fracture geometries. The numerical model allows for two-phase flow and accounts for mutual dissolution of CO2 and water. The solution to this problem is mathematically similar to work on single-phase tracer flow and heat propagation in a fractured environment, but is new in its application to CO2 storage in geological formations.

Effect of Well Orientation (Vertical vs. Horizontal) and Well Length on the Injection of CO2 in Deep Saline Aquifers

Simulations of CO2 injection into confined saline aquifers were conducted for both vertical and horizontal injection wells. The metrics used in quantifying the performances of different injection scenarios included changes in pressure near the injection well, mass of CO2 dissolved into brine (solubility trapping), and storage efficiency, all evaluated with an assumed injection period of 50 years. Metrics were quantified as functions of well length, well orientation, CO2 injection rate, and formation anisotropy (ratio of vertical to horizontal conductivity). When equal well lengths are compared, there is not a significant difference between the predicted performances of horizontal and vertical wells. However, the length of a horizontal well may exceed the length of a vertical well because the length of the horizontal well is not constrained to the vertical thickness of the geologic formation. Simulations show that, as the length of the horizontal well is allowed to increase, the geologic formation can receive a significantly higher CO2 injection rate without exceeding a maximum allowable pressure. This result is observed in both isotropic and anisotropic formations, and suggests that horizontal wells may be advantageous under pressure-limited conditions. However, the use of horizontal wells does not significantly improve the storage efficiency, and under strongly anisotropic conditions, a vertical well provides higher storage efficiency than a horizontal well. We conclude that horizontal wells may be preferable if the goal is to sequester a large amount of CO2 in a short period of time, but do not offer a significant advantage in terms of long-term capacity of a potential repository.

Coupled Reactive Transport Model for Heat and Density Driven Flow in CO2 Storage in Saline Aquifers

In this paper, a novel reactive diffusion-convection transport model is proposed to investigate the flow during different CO2 trappings in deep saline aquifers. Dissolved and immiscible CO2 have trapping times ranging from 1 million to several million years. The mineral trapping has a much longer temporal scale than the solubility trapping. The fine resolution of diffusion-to-advection characteristics is mapped by a corresponding implementation of finite-element numerical simulation. The diffusivity and reaction rate has prominent effects on diffusion-convection-reaction behaviors of the CO2-brine system. The 2-D numerical solutions give insight into the trapping evolution of injected CO2 in a deep subsurface environment.