Probabilistic Analysis of Fracture Reactivation Associated with Deep Underground CO2 Injection

In the context of carbon capture and storage, deep underground injection of CO₂ induces the geomechanical changes within and around the injection zone and their impact on CO₂ storage security should be evaluated. In this study, we conduct coupled multiphase fluid flow and geomechanical modeling to investigate such geomechanical changes, focusing on probabilistic analysis of injection-induced fracture reactivation (such as shear slip) that could lead to enhanced permeability and CO₂ migration across otherwise low-permeability caprock formations. Fracture reactivation in terms of shear slip was analyzed by implicitly considering the fracture orientations generated using the Latin hypercube sampling method, in one case using published fracture statistics from a CO₂ storage site. The analysis was conducted by a coupled multiphase fluid flow and geomechanical simulation to first calculate the three-dimensional stress evolution during a hypothetical CO₂ injection operation and then evaluate the probability of shear slip considering the statistical fracture distribution and a Coulomb failure analysis. We evaluate the probability of shear slip at different points within the injection zone and in the caprock just above the injection zone and relate this to the potential for opening of new flow paths through the caprock. Our analysis showed that a reverse faulting stress field would be most favorable for avoiding fracture shear reactivation, but site-specific analyses will be required because of strong dependency of the local stress field and fracture orientations.     

Numerical simulation and optimization of CO2 sequestration in saline aquifers for vertical and horizontal well injection

With heightened concerns on CO₂ emissions from pulverized-coal (PC) power plants, there has been major emphasis in recent years on the development of safe and economical geological carbon sequestration (GCS) technology. Saline aquifers are considered very attractive for GCS because of their large storage capacity in U.S. and other parts of the world for long-term sequestration. However, uncertainties about storage efficiency as well as leakage risks remain major areas of concern that need to be addressed before the saline aquifers can be fully exploited for carbon sequestration. A genetic algorithm-based optimizer has been developed and coupled with the well-known multiphase numerical solver TOUGH2 to optimally examine various injection strategies for increasing the CO₂ storage efficiency as well as for reducing its plume migration. The optimal injection strategies for CO₂ injection employing a vertical injection well and a horizontal injection well are considered. To ensure the accuracy of the results, the combined hybrid numerical solver/optimizer code was validated by conducting simulations of three widely used benchmark problems employed by carbon sequestration researchers worldwide. The validated code is then employed to optimize the proposed water-alternating-gas injection scheme for CO₂ sequestration using both the vertical and the horizontal injection wells. The results suggest the potential benefits of CO₂ migration control and dissolution. The optimization capability of the hybrid code holds a great promise in studying a host of other problems in GCS, namely how to optimally enhance capillary trapping, accelerate the dissolution of CO₂ in water or brine, and immobilize the CO₂ plume.     

Feasibility of geoelectrical monitoring and multiphase modeling for process understanding of gaseous CO2 injection into a shallow aquifer

Potential pathways in the subsurface may allow upwardly migrating gaseous CO₂ from deep geological storage formations to be released into near surface aquifers. Consequently, the availability of adequate methods for monitoring potential CO₂ releases in both deep geological formations and the shallow subsurface is a prerequisite for the deployment of Carbon Capture and Storage technology. Geoelectrical surveys are carried out for monitoring a small-scale and temporally limited CO₂ injection experiment in a pristine shallow aquifer system. Additionally, the feasibility of multiphase modeling was tested in order to describe both complex non-linear multiphase flow processes and the electrical behavior of partially saturated heterogeneous porous media. The suitability of geoelectrical methods for monitoring injected CO₂ and geochemically altered groundwater was proven. At the test site, geoelectrical measurements reveal significant variations in electrical conductivity in the order of 15?C30?%. However, site-specific conditions (e.g., geological settings, groundwater composition) significantly influence variations in subsurface electrical conductivity and consequently, the feasibility of geoelectrical monitoring. The monitoring results provided initial information concerning gaseous CO₂ migration and accumulation processes. Geoelectrical monitoring, in combination with multiphase modeling, was identified as a useful tool for understanding gas phase migration and mass transfer processes that occur due to CO₂ intrusions in shallow aquifer systems.     

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

Carbon dioxide (CO₂) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO₂ injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO₂ supply or during required system maintenance. CO₂ injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO₂ storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO₂ sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO₂ injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO₂ injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO₂ injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.     

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.     

Geomechanical and geochemical effects on sandstones caused by the reaction with supercritical CO2: an experimental approach to in situ conditions in deep geological reservoirs

The geochemical and geomechanical behaviour of reservoir rocks from deep saline aquifers during the injection and geological storage of CO₂ is studied in laboratory experiments. A combination of geochemical and geomechanical studies was carried out on various sandstones from the North German Basin. After the mineralogical, geochemical and petrophysical characterization, a set of sandstone samples was exposed to supercritical (sc)CO₂ and brine for 2–4 weeks in an autoclave system. One sample was mineralogically and geochemically characterised and then loaded in a triaxial cell under in situ pressure and temperature conditions to study the changes of the geomechanical rock properties. After treatment in the autoclaves, geochemical alterations mainly in the carbonate, but also in the sheet silicate cements as well as in single minerals of the sandstones were observed, affecting the rocks granular structure. In addition to partial solution effects during the geochemical experiments, small grains of secondary carbonate and other mineral precipitations were observed within the pore space of the treated sandstones. Results of additional geomechanical experiments with untreated samples show that the rock strength is influenced by the saturation degree, the confining pressure, the pore fluid pressure and temperature. The exposure to pure scCO₂ in the autoclave system induces reduced strength parameters, modified elastic deformation behaviour and changes of the effective porosity in comparison to untreated sandstone samples. Experimental results show that the volume of pore fluid fluxing into the pore space of the sandstones clearly depends on the saturation level of the sample.     

Effects of in-situ conditions on relative permeability characteristics of CO2-brine systems

Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO₂ storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO₂-brine systems at in-situ conditions is essential in ascertaining CO₂ injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO₂ storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO₂-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO₂-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.     

A comparative review of hydrologic issues involved in geologic storage of CO<Subscript>2</Subscript> and injection disposal of liquid waste

The paper presents a comparison of hydrologic issues and technical approaches used in deep-well injection and disposal of liquid wastes, and those issues and approaches associated with injection and storage of CO₂ in deep brine formations. These comparisons have been discussed in nine areas: injection well integrity; abandoned well problems; buoyancy effects; multiphase flow effects; heterogeneity and flow channeling; multilayer isolation effects; caprock effectiveness and hydromechanics; site characterization and monitoring; effects of CO₂ storage on groundwater resources. There are considerable similarities, as well as significant differences. Scientifically and technically, these two fields can learn much from each other. The discussions presented in this paper should help to focus on the key scientific issues facing deep injection of fluids. A substantial but by no means exhaustive reference list has been provided for further studies into the subject.     

Europe’s longest-operating on-shore CO2 storage site at Ketzin, Germany: a progress report after three years of injection

The Ketzin pilot site, led by the GFZ German Research Centre for Geosciences, is Europe??s longest-operating on-shore CO₂ storage site with the aim of increasing the understanding of geological storage of CO₂ in saline aquifers. Located near Berlin, the Ketzin pilot site is an in situ laboratory for CO₂ storage in an anticlinal structure in the Northeast German Basin. Starting research within the framework of the EU project CO₂SINK in 2004, Ketzin is Germany??s first CO₂ storage site and fully in use since the injection began in June 2008. After 39?months of operation, about 53,000 tonnes of CO₂ have been stored in 630?C650?m deep sandstone units of the Upper Triassic Stuttgart Formation. An extensive monitoring program integrates geological, geophysical and geochemical investigations at Ketzin for a comprehensive characterization of the reservoir and the CO₂ migration at various scales. Integrating a unique field and laboratory data set, both static geological modeling and dynamic simulations are regularly updated. The Ketzin project successfully demonstrates CO₂ storage in a saline aquifer on a research scale. The results of monitoring and modeling can be summarized as follows: (1) Since the start of the CO₂ injection in June 2008, the operation has been running reliably and safely. (2) Downhole pressure data prove correlation between the injection rate and the reservoir pressure and indicates the presence of an overall dynamic equilibrium within the reservoir. (3) The extensive geochemical and geophysical monitoring program is capable of detecting CO₂ on different scales and gives no indication for any leakage. (4) Numerical simulations (history matching) are in good agreement with the monitoring results.     

Geomechanical modelling to assess fault integrity at the CO2CRC Otway Project,Australia

This paper presents the first published 3D geomechanical modelling study of the CO2CRC Otway Project, located in the state of Victoria, Australia. The results of this work contribute to one of the main objectives of the CO2CRC, which is to demonstrate the feasibility of CO₂ storage in a depleted gas reservoir. With this aim in mind, a one-way coupled flow and geomechanics model is presented, with the capability of predicting changes to the in situ stress field caused by changes in reservoir pressure owing to CO₂ production and injection. A parametric study investigating the pore pressures required to reactivate key, reservoir-bounding faults has been conducted, and the results from the numerical simulation and analytical analysis are compared. The numerical simulation indicates that the critical pore fluid pressure to cause fault reactivation is 1.15 times the original pressure as opposed to 1.5 times for the comparable analytical model. Possible reasons for the differences between the numerical and analytical models can be ascribed to the higher degree of complexity incorporated in the numerical model. Heterogeneity in terms of lateral variations of hydrological and mechanical parameters, effect of topography, presence of faults and interaction between cells are considered to be the main sources for the different estimation of critical pore pressure. The numerical model, which incorporates this greater complexity, is able then to better describe the state of stress that acts in the subsurface compared with a simple 1D analytical model. Moreover, the reactivation pressures depend mainly on the state of stress described; therefore we suggest that numerical models be performed when possible.     

Seismicity and fault aseismic deformation caused by fluid injection in decametric in-situ experiments

Seismicity induced by fluid perturbations became an important societal concern since felt earthquakes (M_w up to 6) occurred after anthropogenic activities. In order to mitigate the risks associated with undesired seismicity, as well as to be able to use the micro-seismicity as a probe for in-depth investigation of fluid-driven processes, it is of crucial importance to understand the links between seismicity, fluid pressure and flow. We have developed a series of in-situ, decameter-scale experiments of fault zone reactivation by controlled fluid injection, in order to improve the near-source geophysical and hydromechanical observations. The deployed geophysical monitoring close to the injection allows one to cover the full frequency range of the fault responses from the static deformation to the very high-frequency seismic emissions (up to 4 kHz). Here, we focus on the microseismicity (M_w ∼ –4 to –3) recorded during two fluid injection experiments in low-permeable shale and highly-fractured limestone formations. In both experiments, the spatio-temporal distribution of the seismic events, the energy balance, and the seismic velocity changes of the fractured medium show that most of the deformation does not actually emit seismic signals. The induced deformation is mainly aseismic. Based on these high-resolution multiparametric observations in the near-field, we therefore proposed a new model for injection-induced seismicity: the seismicity is not directly induced by the increasing fluid pressure, but it is rather triggered by the stress perturbations transferred from the aseismic motion caused by the injection.     

Exhaustive brine production and complete CO2 storage in Jianghan Basin of China

Pressure buildup limits CO₂ injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO₂ storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO₂ storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO₂ injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO₂ injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO₂ injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO₂ injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO₂ injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement.     

A stochastic inversion workflow for monitoring the distribution of CO<Subscript>2</Subscript> injected into deep saline aquifers

We present a two-step stochastic inversion approach for monitoring the distribution of CO₂ injected into deep saline aquifers for the typical scenario of one single injection well and a database comprising a common suite of well logs as well as time-lapse vertical seismic profiling (VSP) data. In the first step, we compute several sets of stochastic models of the elastic properties using conventional sequential Gaussian co-simulations (SGCS) representing the considered reservoir before CO₂ injection. All realizations within a set of models are then iteratively combined using a modified gradual deformation algorithm aiming at reducing the mismatch between the observed and simulated VSP data. In the second step, these optimal static models then serve as input for a history matching approach using the same modified gradual deformation algorithm for minimizing the mismatch between the observed and simulated VSP data following the injection of CO₂. At each gradual deformation step, the injection and migration of CO₂ is simulated and the corresponding seismic traces are computed and compared with the observed ones. The proposed stochastic inversion approach has been tested for a realistic, and arguably particularly challenging, synthetic case study mimicking the geological environment of a potential CO₂ injection site in the Cambrian-Ordivician sedimentary sequence of the St. Lawrence platform in Southern Québec. The results demonstrate that the proposed two-step reservoir characterization approach is capable of adequately resolving and monitoring the distribution of the injected CO₂. This finds its expression in optimized models of P- and S-wave velocities, density, and porosity, which, compared to conventional stochastic reservoir models, exhibit a significantly improved structural similarity with regard to the corresponding reference models. The proposed approach is therefore expected to allow for an optimal injection forecast by using a quantitative assimilation of all available data from the appraisal stage of a CO₂ injection site.     

Review: The potential impact of underground geological storage of carbon dioxide in deep saline aquifers on shallow groundwater resources

Underground geological storage of CO₂ in deep saline aquifers is considered for reducing greenhouse gases emissions into the atmosphere. However, some issues were raised with regard to the potential hazards to shallow groundwater resources from CO₂ leakage, brine displacement and pressure build-up. An overview is provided of the current scientific knowledge pertaining to the potential impact on shallow groundwater resources of geological storage of CO₂ in deep saline aquifers, identifying knowledge gaps for which original research opportunities are proposed. Two main impacts are defined and discussed therein: the near-field impact due to the upward vertical migration of free-phase CO₂ to surficial aquifers, and the far-field impact caused by large-scale displacement of formation waters by the injected CO₂. For the near-field, it is found that numerical studies predict possible mobilization of trace elements but concentrations are rarely above the maximum limit for potable water. For the far-field, numerical studies predict only minor impacts except for some specific geological conditions such as high caprock permeability. Despite important knowledge gaps, the possible environmental impacts of geological storage of CO₂ in deep saline aquifers on shallow groundwater resources appears to be low, but much more work is required to evaluate site specific impacts.     

Potential and Suitability Evaluation of CO2 Geological Storage in Major Sedimentary Basins of China, and the Demonstration Project in Ordos Basin

From 2010 to 2012, the China Geological Survey Center for Hydrogeology and Environmental Geology Survey (CHEGS) carried out the project “Potential evaluation and demonstration project of CO2 Geological Storage in China”. During this project, we developed an evaluation index system and technical methods for the potential and suitability of CO2 geological storage based on China’s geological conditions, and evaluated the potential and suitability of the primary basins for CO2 geological storage, in order to draw a series of regional scale maps (at a scale of 1:5000000) and develop an atlas of the main sedimentary basins in China. By using these tools, we delineated many potential targets for CO2 storage. We also built techniques and methods for site selection and the exploration and assessment of CO2 geological storage in deep saline aquifers. Furthermore, through cooperation with the China Shenhua Coal to Liquid and Chemical Co., Ltd., we successfully constructed the first coal-based demonstration project for CO2 geological storage in deep saline aquifers in the Yijinhuoluo Banner of Ordos in the Inner Mongolia Autonomous Region, which brought about the basic preliminary theories, techniques, and methods of geological CO2 storage in deep saline aquifers under China’s geological conditions.     

Assessing the potential consequences of CO2 leakage to freshwater resources: A batch-reaction experiment towards an isotopic tracing tool

The assessment of the environmental impacts of CO₂ geological storage requires the investigation of potential CO₂ leakages into fresh groundwater, particularly with respect to protected groundwater resources. The geochemical processes and perturbations associated with a CO₂ leak into fresh groundwater could alter groundwater quality: indeed, some of the reacting minerals may contain hazardous constituents, which might be released into groundwater. Since the geochemical reactions may occult direct evidence of intruding CO₂, it is necessary to characterize these processes and identify possible indirect indicators for monitoring CO₂ intrusion. The present study focuses on open questions: Can changes in water quality provide evidence of CO₂ leakage? Which parameters can be used to assess impact on freshwater aquifers? What is the time scale of water chemistry degradation in the presence of CO₂? The results of an experimental approach allow selecting pertinent isotope tracers as possible indirect indicators of CO₂ presence, opening the way to devise an isotopic tracing tool.The study area is located in the Paris Basin (France), which contains deep saline formations identified as targets by French national programs for CO₂ geological storage. The study focuses on the multi-layered Albian fresh water aquifer, confined in the central part of the Paris Basin a major strategic potable groundwater overlying the potential CO₂ storage formations. An experimental approach (batch reactors) was carried out in order to better understand the rock–water–CO₂ interactions with two main objectives. The first was to assess the evolution of the formation water chemistry and mineralogy of the solid phase over time during the interaction. The second concerned the design of an isotopic monitoring program for freshwater resources potentially affected by CO₂ leakage. The main focus was to select suitable environmental isotope tracers to track water rock interaction associated with small quantities of CO₂ leaking into freshwater aquifers.In order to improve knowledge on the Albian aquifer, and to provide representative samples for the experiments, solid and fluid sampling campaigns were performed throughout the Paris Basin. Albian groundwater is anoxic with high concentrations of Fe, a pH around 7 and a mineral content of 0.3 g L⁻¹. Macroscopic and microscopic solid analyses showed a quartz-rich sand with the presence of illite/smectite, microcline, apatite and glauconite. A water–mineral–CO₂ interaction batch experiment was used to investigate the geochemical evolution of the groundwater and the potential release of hazardous trace elements. It was complemented by a multi-isotope approach including δ¹³C_DIC and ⁸⁷Sr/⁸⁶Sr. Here the evolution of the concentrations of major and trace elements and isotopic ratios over batch durations from 1 day to 1 month are discussed. Three types of ion behavior are observed: Type I features Ca, SiO₂, HCO₃, F, PO₄, Na, Al, B, Co, K, Li, Mg, Mn, Ni, Pb, Sr, Zn which increased after initial CO₂ influx. Type II comprises Be and Fe declining at the start of CO₂ injection. Then, type III groups element with no variation during the experiments like Cl and SO₄. The results of the multi-isotope approach show significant changes in isotopic ratios with time. The contribution of isotope and chemical data helps in understanding geochemical processes involved in the system. The isotopic systems used in this study are potential indirect indicators of CO₂–water–rock interaction and could serve as monitoring tools of CO₂ leakage into an aquifer overlying deep saline formations used for C sequestration and storage.     

Acid-gas injection at West Stoddart, British Columbia: An analogue for the detailed hydrogeological characterization of a CO2 sequestration site

Geological sequestration of CO₂ is an option for significantly reducing emissions into the atmosphere. Various hydrocarbon companies in western Canada are currently injecting acid-gas (CO₂ and H₂S) into deep subsurface formations. At West Stoddart, in northeast British Columbia, acid-gas has been injected since 1998 at 1600 m depth into sandstones of the Triassic Halfway Formation, which forms a regional aquifer. A comprehensive subsurface characterization was conducted of the regional and local-scale geology, reservoir characteristics, mineralogy, in situ fluid properties, and hydrogeology. Preliminary results from geochemical and numerical multi-phase flow modelling suggest that the majority of the injected acid-gas will dissolve in the formation water and remain within a radius of a few kilometres of the injection well. The experience with the acid-gas injection at West Stoddart and other operations in the Alberta Basin has shown that the process of large-scale CO₂-injection into deep aquifers is technically feasible.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO₂) because of the many physical and chemical processes impacting CO₂ movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO₂ storage. However, only through the injection and monitoring of CO₂ itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO₂ injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO₂ plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO₂ injection and then CO₂ injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO₂ movement in the subsurface is monitored by sampling fluid at an observation well, running CO₂-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO₂ plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.