Feasibility of CO<Subscript>2</Subscript> migration detection using pressure and CO<Subscript>2</Subscript> saturation monitoring above an imperfect primary seal of a geologic CO<Subscript>2</Subscript> storage formation: a numerical investigation

A numerical model was developed to investigate the potential to detect fluid migration in a (homogeneous, isotropic, with constant pressure lateral boundaries) porous and permeable interval overlying an imperfect primary seal of a geologic CO₂ storage formation. The seal imperfection was modeled as a single higher-permeability zone in an otherwise low-permeability seal, with the center of that zone offset from the CO₂ injection well by 1400 m. Pressure response resulting from fluid migration through the high-permeability zone was detectable up to 1650 m from the centroid of that zone at the base of the monitored interval after 30 years of CO₂ injection (detection limit = 0.1 MPa pressure increase); no pressure response was detectable at the top of the monitored interval at the same point in time. CO₂ saturation response could be up to 774 m from the center of the high-permeability zone at the bottom of the monitored interval, and 1103 m at the top (saturation detection limit = 0.01). More than 6% of the injected CO₂, by mass, migrated out of primary containment after 130 years of site performance (including 30 years of active injection) in the case where the zone of seal imperfection had a moderately high permeability (10^??17 m² or 0.01 mD). Free-phase CO₂ saturation monitoring at the top of the overlying interval provides favorable spatial coverage for detecting fluid migration across the primary seal. Improved sensitivity of detection for pressure perturbation will benefit time of detection above an imperfect seal.     

Experimental investigation into the sealing capability of naturally fractured shale caprocks to supercritical carbon dioxide flow

Geological storage of CO₂ is considered a solution for reducing the excess CO₂ released into the atmosphere. Low permeability caprocks physically trap CO₂ injected into underlying porous reservoirs. Injection leads to increasing pore pressure and reduced effective stress, increasing the likelihood of exceeding the capillary entry pressure of the caprocks and of caprock fracturing. Assessing on how the different phases of CO₂ flow through caprock matrix and fractures is important for assessing CO₂ storage security. Fractures are considered to represent preferential flow paths in the caprock for the escape of CO₂. Here we present a new experimental rig which allows 38 mm diameter fractured caprock samples recovered from depths of up to 4 km to be exposed to supercritical CO₂ (scCO₂) under in situ conditions of pressure, temperature and geochemistry. In contrast to expectations, the results indicate that scCO₂ will not flow through tight natural caprock fractures, even with a differential pressure across the fractured sample in excess of 51 MPa. However, below the critical point where CO₂ enters its gas phase, the CO₂ flows readily through the caprock fractures. This indicates the possibility of a critical threshold of fracture aperture size which controls CO₂ flow along the fracture.     

Numerical simulation of carbon dioxide migration in a sandstone aquifer considering the fluid–solid coupling

Very limited investigations have been done on the numerical simulation of carbon dioxide (CO₂) migration in sandstone aquifers taking consideration of the interactions between fluid flow and rock stress. Based on the poroelasticity theory and multiphase flow theory, this study establishes a mathematical model to describe CO₂ migration, coupling the flow and stress fields. Both finite difference method (FDM) and finite element method (FEM) were used to discretize the mathematical model and generate a numerical model. A case study was carried out using the numerical model on the Jiangling sandstone aquifer in the Jianghan basin, China. The rock mechanics parameters of reservoir and overlying strata of Jiangling depression were obtained by triaxial tests. A two-dimensional model was then built to simulate carbon dioxide migration in the sandstone aquifer. The numerical simulation analyzes the carbon dioxide migration distribution rule with and without considering capillary pressure. Time-dependent migration of CO₂ in the sandstone aquifer was analyzed, and the result from the coupled model was compared with that from a traditional non-coupled model. The calculation result indicates a good consistency between the coupled model and the non-coupled model. At the injection point, the CO₂ saturation given by the coupled model is 15.39 % higher than that given by the non-coupled model; while the pore pressure given by the coupled model is 4.8 % lower than that given by the non-coupled model. Therefore, it is necessary to consider the coupling of flow and stress fields while simulating CO₂ migration for CO₂ disposal in sandstone aquifers. The result from the coupled model was also sensitized to several parameters including reservoir permeability, porosity, and CO₂ injection rate. Sensitivity analyses show that CO₂ saturation is increased non-linearly with CO₂ injection rate and decreased non-linearly with reservoir porosity. Pore pressure is decreased non-linearly with reservoir porosity and permeability, and increased non-linearly with CO₂ injection rate. When the capillary pressure was considered, the computed gas saturation of carbon dioxide was increased by 10.75 % and the pore pressure was reduced by 0.615 %.     

A network flow model for the genesis and migration of gas phase

We present a network flow model to compute transport, through a pore network, of a compositional fluid consisting of water with a dissolved hydrocarbon gas. The model captures single-phase flow (below local bubble point conditions) as well as the genesis and migration of the gas phase when bubble point conditions are achieved locally. Constant temperature computational tests were run on simulated 2D and 3D micro-networks near bubble point pressure conditions. In the 2D simulations which employed a homogeneous network, negligible capillary pressure, and linear relative permeability relations, the observed concentration of CO₂ dissolved in the liquid phase throughout the medium was linearly related to the liquid pressure. In the case of no gravity, the saturation of the gas phase throughout the medium was also linearly related to the liquid pressure; under gravity, the relationship became nonlinear in regions where buoyancy forces were significant. The 3D heterogeneous network model had nonnegligible capillary pressure and nonlinear relative permeability functions. While 100 % of the CO₂ entered the 3D network dissolved in the liquid phase, 25 % of the void space was occupied by gas phase and 47 % of the CO₂ exiting the outlet face did so via the gaseous phase after 500 s of simulation time.     

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin,China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO₂ from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO₂ plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO₂ gas saturation and mass fraction of dissolved CO₂ in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO₂ injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO₂ injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO₂ plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO₂–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO₂ injection scheme still requires pursuance of further studies.     

Modeling, parameterization and evaluation of monitoring methods for CO2 storage in deep saline formations: the CO2-MoPa project

Capture and geological sequestration of CO₂ from large industrial sources is considered a measure for reducing anthropogenic emissions of CO₂ and thus mitigating climate change. One of the main storage options proposed are deep saline formations, as they provide the largest potential storage capacities among the geologic options. A thorough assessment of this type of storage site therefore is required. The CO₂-MoPa project aims at contributing to the dimensioning of CO₂ storage projects and to evaluating monitoring methods for CO₂ injection by an integrated approach. For this, virtual, but realistic test sites are designed geometrically and fully parameterized. Numerical process models are developed and then used to simulate the effects of a CO₂ injection into the virtual test sites. Because the parameterization of the virtual sites is known completely, investigation as well as monitoring methods can be closely examined and evaluated by comparing the virtual monitoring result with the simulation. To this end, the monitoring or investigation method is also simulated, and the (virtual) measurements are recorded and evaluated like real data. Application to a synthetic site typical for the north German basin showed that pressure response has to be evaluated taking into account the layered structure of the storage system. Microgravimetric measurements are found to be promising for detecting the CO₂ phase distribution. A combination of seismic and geoelectric measurements can be used to constrain the CO₂ phase distribution for the anticline system used in the synthetic site.     

Phase-equilibrium geobarometers for silicic rocks based on rhyolite-MELTS. Part 1: Principles,procedures, and evaluation of the method

Constraining the pressure of crystallization of magmas is an important but elusive task. In this work, we present a method to derive crystallization pressures for rocks that preserve glass compositions (either glass inclusions or matrix glass) representative of equilibration between melt, quartz, and 1 or 2 feldspars. The method relies on the well-known shift of the quartz–feldspar saturation surface toward higher normative quartz melt compositions with decreasing pressure. The critical realization for development of the method is the fact that melt, quartz and feldspars need to be in equilibrium at the liquidus for the melt composition. The method thus consists of calculating the saturation surfaces for quartz and feldspars using rhyolite-MELTS over a range of pressures, and searching for the pressure at which the expected assemblage (quartz+1 feldspar or quartz+2 feldspars) is found at the liquidus. We evaluate errors resulting from uncertainties in glass composition using a series of Monte Carlo simulations for a quartz-hosted glass inclusion composition from the Bishop Tuff, which reveal errors on the order of 20–45 MPa for the quartz+2 feldspars constraint and on the order of 25–100 MPa for the quartz+1 feldspar constraint; we suggest actual errors are closer to the lower bounds of these ranges. We investigate the effect of fluid saturation in two ways: (1) By applying our procedure over a range of water contents for three glass compositions; we show that the effect of fluid saturation is more important at higher pressures (~300 MPa) than at lower pressures (~100 MPa), but reasonable pressure estimates can be derived irrespective of fluid saturation for geologically relevant H₂O concentrations >3 wt% and (2) by performing the same type of pressure determinations with a preliminary version of rhyolite-MELTS that includes a H₂O–CO₂ mixed fluid phase; we use a range of H₂O and CO₂ concentrations for two compositions characteristic of early-erupted and late-erupted Bishop Tuff glass inclusions and demonstrate that calculated pressures are largely independent of CO₂ concentration (for CO₂ <1,000 ppm), at least for relatively high H₂O contents, as expected in most natural magmas, such that CO₂ concentration can be effectively neglected for application of our method. Finally, we demonstrate that pressures calculated using the rhyolite-MELTS geobarometer compare well with those resulting from H₂O–CO₂ glass inclusion barometry and Al-in-hornblende barometry for an array of natural systems for which data have been compiled from the literature; the agreement is best for quartz-hosted glass inclusions, while matrix glass yields systematically lower rhyolite-MELTS pressures, suggestive of melt evolution during eruptive decompression.     

A discontinuous Galerkin method for two-phase flow in a porous medium enforcing H(div) velocityand continuous capillary pressure

We consider the slightly compressible two-phase flow problem in a porous medium with capillary pressure. The problem is solved using the implicit pressure, explicit saturation (IMPES) method, and the convergence is accelerated with iterative coupling of the equations. We use discontinuous Galerkin to discretize both the pressure and saturation equations. We apply two improvements, which are projecting the flux to the mass conservative H(div)-space and penalizing the jump in capillary pressure in the saturation equation. We also discuss the need and use of slope limiters and the choice of primary variables in discretization. The methods are verified with two- and three-dimensional numerical examples. The results show that the modifications stabilize the method and improve the solution.     

Sensitivity study of pulsed neutron-gamma saturation monitoring at the Altmark site in the context of CO2 storage

The injection of CO₂ into depleted natural gas reservoirs has been proposed as a promising new technology for combining enhanced gas recovery and geological storage of CO₂. During the injection, application of suitable techniques for monitoring of the induced changes in the subsurface is required. Observing the movement and the changes in saturation of the fluids contained in the reservoir and the confining strata is among the primary aims here. It is shown that under conditions similar to the Altmark site, Germany, pulsed neutron-gamma logging can be applied with limitations. The pulsed neutron-gamma method can be applied for detection and quantification of changes in brine saturation and water content, whereas changes in the gas composition are below the detection limit. A method to account for the effects of salt precipitation resulting from evaporation of residual brine is presented.     

Uncertainties of geochemical modeling during CO<Subscript>2</Subscript> sequestration applying batch equilibrium calculations

One of the uncertainties in the field of carbon dioxide capture and storage (CCS) is caused by the parameterization of geochemical models. The application of geochemical models contributes significantly to calculate the fate of the CO₂ after its injection. The choice of the thermodynamic database used, the selection of the secondary mineral assemblage as well as the option to calculate pressure dependent equilibrium constants influence the CO₂ trapping potential and trapping mechanism. Scenario analyses were conducted applying a geochemical batch equilibrium model for a virtual CO₂ injection into a saline Keuper aquifer. The amount of CO₂ which could be trapped in the formation water and in the form of carbonates was calculated using the model code PHREEQC. Thereby, four thermodynamic datasets were used to calculate the thermodynamic equilibria. Furthermore, the equilibrium constants were re-calculated with the code SUPCRT92, which also applied a pressure correction to the equilibrium constants. Varying the thermodynamic database caused a range of 61% in the amount of trapped CO₂ calculated. Simultaneously, the assemblage of secondary minerals was varied, and the potential secondary minerals dawsonite and K-mica were included in several scenarios. The selection of the secondary mineral assemblage caused a range of 74% in the calculated amount of trapped CO₂. Correcting the equilibrium constants with respect to a pressure of 125 bars had an influence of 11% on the amount of trapped CO₂. This illustrates the need for incorporating sensitivity analyses into reaction pathway modeling.     

Post-injection trapping of mobile CO<Subscript><Emphasis Type="Bold">2</Emphasis></Subscript> in deep aquifers: Assessing the importance of model and parameter uncertainties

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

Fully-implicit simulation of vertical-equilibrium models with hysteresis and capillary fringe

Geological carbon storage represents a new and substantial challenge for the subsurface geosciences. To increase understanding and make good engineering decisions, containment processes and large-scale storage operations must be simulated in a thousand year perspective. A hierarchy of models of increasing computational complexity for analysis and simulation of large-scale CO₂ storage has been implemented as a separate module of the open-source Matlab Reservoir Simulation Toolbox (MRST). This paper describes a general family of two-scale models available in this module. The models consist of two-dimensional flow equations formulated in terms of effective quantities obtained from hydrostatic reconstructions of vertical pressure and saturation distributions. The corresponding formulation is fully implicit and is the first to give a mass-conservative treatment and include general (non-linearized) CO₂ properties. In particular, the models account for compressibility, dissolution, and hysteresis effects in the fine-scale capillary and relative permeability functions and can be used to accurately and efficiently study the combined large-scale and long-term effects of structural, residual, and solubility trapping.     

Multiphase flow modeling with general boundary conditions and automatic phase-configuration changes using a fractional-flow approach

The multiphase flow simulator moving particle semi-implicit (MPS) method is developed based on the fractional-flow approach, originated in the petroleum engineering literature, considering the fully three-phase flow with general boundary conditions. The fractional flow approach employs water saturation, total liquid saturation, and total pressure as primary variables. Most existing models based upon fractional flow are limited to two-phase flow and specific boundary conditions. Although there appear a number of three-phase flow models, they were mostly developed using pressure-based approaches, which require variable-switch techniques to deal with phase appearance and disappearance. The use of fractional flow-based approaches in MPS makes it unnecessary to use variable-switching to handle the change of phase configurations because the water saturation, total liquid saturation, and total pressure exist throughout the solution domain regardless of whether certain phases are present or not. Furthermore, most existing fractional flow-based models consider only specific boundary conditions, usually Dirichlet-type pressure for water phase and flux-type boundary for nonaqueous phase liquid or particular combinations for individual phase. However, the present model considers general boundary conditions of ten most possible and plausible cases. The first eight cases are the combinations of the phase pressure or the phase flux of each of the three individual phases. The other two cases are the variable boundary conditions: one for water-medium interface and the other for the air-medium interface when the directions of fluxes are not known a priori. Thus, the model’s capabilities of handling general boundary conditions extend the simulators’ usefulness in the field system.     

Immiscible two-phase Darcy flow model accounting for vanishing and discontinuous capillary pressures: application to the flow in fractured porous media

Fully implicit time-space discretizations applied to the two-phase Darcy flow problem leads to the systems of nonlinear equations, which are traditionally solved by some variant of Newton’s method. The efficiency of the resulting algorithms heavily depends on the choice of the primary unknowns since Newton’s method is not invariant with respect to a nonlinear change of variable. In this regard, the role of capillary pressure/saturation relation is paramount because the choice of primary unknowns is restricted by its shape. We propose an elegant mathematical framework for two-phase flow in heterogeneous porous media resulting in a family of formulations, which apply to general monotone capillary pressure/saturation relations and handle the saturation jumps at rocktype interfaces. The presented approach is applied to the hybrid dimensional model of two-phase water-gas Darcy flow in fractured porous media for which the fractures are modelled as interfaces of co-dimension one. The problem is discretized using an extension of vertex approximate gradient scheme. As for the phase pressure formulation, the discrete model requires only two unknowns by degree of freedom.     

Sealing efficiency analysis for shallow-layer caprocks in CO<Subscript>2</Subscript> geological storage

The CO₂ migrated from deeper to shallower layers may change its phase state from supercritical state to gaseous state (called phase transition). This phase transition makes both viscosity and density of CO₂ experience a sharp variation, which may induce the CO₂ further penetration into shallow layers. This is a critical and dangerous situation for the security of CO₂ geological storage. However, the assessment of caprock sealing efficiency with a fully coupled multi-physical model is still missing on this phase transition effect. This study extends our previous fully coupled multi-physical model to include this phase transition effect. The dramatic changes of CO₂ viscosity and density are incorporated into the model. The impacts of temperature and pressure on caprock sealing efficiency (expressed by CO₂ penetration depth) are then numerically investigated for a caprock layer at the depth of 800 m. The changes of CO₂ physical properties with gas partial pressure and formation temperature in the phase transition zone are explored. It is observed that phase transition revises the linear relationship of CO₂ penetration depth and time square root as well as penetration depth. The real physical properties of CO₂ in the phase transition zone are critical to the safety of CO₂ sequestration. Pressure and temperature have different impact mechanisms on the security of CO₂ geological storage.     

Determining phase volumes of mixed CO2-H2O inclusions using microthermometric measurements

A new graphical technique has been developed which permits the composition and volumetric properties of mixed CO₂-H₂O inclusions to be determined using microthermometric measurements. If the values of only two of the four variables

Groundwater in fractured crystalline rocks, the Clara mine, Black Forest (Germany)

The chemical composition of water sampled in a 700 m deep underground barite-fluorite mine in the crystalline basement of the Black Forest area (SW Germany) varies systematically with depth and the length of flow paths trough, the fracture porosity of the gneiss matrix. Calcium and sulfate increase as a result of a combined sulfide oxidation and plagioclase alteration reaction. The gneiss contains andesine–plagioclase (An₂₀–An₄₀) and is rich in primary sulfide. As an effect of Ca and SO₄ release by the prime water–rock reaction, dissolved oxygen decreases and the waters become more reduced. The waters have Cl/Br mass ratios of about 50, which is very close to that of experimentally leached gneiss powders indicating that the rock matrix is the source of the halogens. The waters are undersaturated with respect to calcite in the upper parts of the mine. With increasing reaction progress, calcite saturation is reached and carbonate forms as a reaction product of the prime reaction that also controls the partial pressure of CO₂ to progressively lower values. The chemical evolution of groundwater in fractured basement of the Clara mine suggests that the partial pressure of CO₂ is an internally buffered parameter rather than a controlling external variable.     

Modeling of the solubility of a one-component H2O or CO2 fluid in silicate liquids

The modeling of the solubility of water and carbon dioxide in silicate liquids (flash problem) is performed by assuming mechanical, thermal, and chemical equilibrium between the liquid magma and the gas phase. The liquid phase is treated as a mixture of ten silicate components + H₂O or CO₂, and the gas phase as a pure H₂O or CO₂. A general model for the solubility of a volatile component in a liquid is adopted. This requires the definition of a mixing equation for the excess Gibbs free energy of the liquid phase and an appropriate reference state for the dissolved volatile. To constrain the model parameters and identify the most appropriate form of the solubility equations for each dissolved volatile, a large number of experimental solubility determinations (640 for H₂O and 263 for CO₂) have been used. These determinations cover a large region of the P-T-composition space of interest. The resultant water and carbon dioxide solubility models differ in that the water model is regular and isometric, and the carbon dioxide model is regular and non-isometric. This difference is consistent with the different speciation modalities of the two volatiles in the silicate liquids, producing a composition-independent partial molar volume of dissolved water and a composition-dependent partial molar volume of dissolved carbon dioxide. The H₂O solubility model may be applied to natural magmas of virtually any composition in the P-T range 0.1 MPa–1 GPa and > 1000 K, whereas the CO₂ solubility model may be applied to several GPa pressures. The general consistency of the water solubility data and their relatively large number as compared to the calibrated model parameters (11) contrast with the large inconsistencies of the carbon dioxide solubility determinations and their low number with respect to the CO₂ model parameters (22). As a result, most of the solubility data in the database are reproduced within 10% of approximation in the case of water, and 30% in the case of carbon dioxide. When compared with the experimental data, the H₂O and CO₂ solubility models correctly predict many features of the saturation surface in the P-T-composition space, including the change from retrograde to prograde H₂O solubility in albitic liquids with increasing pressure, the so-called alkali effect, the increasing CO₂ solubility with increasing degree of silica undersaturation, the Henrian behavior of CO₂ in most silicate liquids up to about 30–50 MPa, and the proportionality between the fugacity in the gas phase, or the saturation activity in the liquid phase, and the square of the mole fraction of the dissolved volatile found in some unrelated silicate liquid compositions. Received: 21 August 1995 / Accepted: 8 July 1996     

Numerical simulation of CO2 disposal by mineral trapping in deep aquifers

Carbon dioxide disposal into deep aquifers is a potential means whereby atmospheric emissions of greenhouse gases may be reduced. However, our knowledge of the geohydrology, geochemistry, geophysics, and geomechanics of CO₂ disposal must be refined if this technology is to be implemented safely, efficiently, and predictably. As a prelude to a fully coupled treatment of physical and chemical effects of CO₂ injection, the authors have analyzed the impact of CO₂ immobilization through carbonate mineral precipitation. Batch reaction modeling of the geochemical evolution of 3 different aquifer mineral compositions in the presence of CO₂ at high pressure were performed. The modeling considered the following important factors affecting CO₂ sequestration: (1) the kinetics of chemical interactions between the host rock minerals and the aqueous phase, (2) CO₂ solubility dependence on pressure, temperature and salinity of the system, and (3) redox processes that could be important in deep subsurface environments. The geochemical evolution under CO₂ injection conditions was evaluated. In addition, changes in porosity were monitored during the simulations. Results indicate that CO₂ sequestration by matrix minerals varies considerably with rock type. Under favorable conditions the amount of CO₂ that may be sequestered by precipitation of secondary carbonates is comparable with and can be larger than the effect of CO₂ dissolution in pore waters. The precipitation of ankerite and siderite is sensitive to the rate of reduction of Fe(III) mineral precursors such as goethite or glauconite. The accumulation of carbonates in the rock matrix leads to a considerable decrease in porosity. This in turn adversely affects permeability and fluid flow in the aquifer. The numerical experiments described here provide useful insight into sequestration mechanisms, and their controlling geochemical conditions and parameters.