An integrative approach to robust design and probabilistic risk assessment for CO<Subscript>2</Subscript> storage in geological formations

CO₂ storage in geological formations is currently being discussed intensively as a technology with a high potential for mitigating CO₂ emissions. However, any large-scale application requires a thorough analysis of the potential risks. Current numerical simulation models are too expensive for probabilistic risk analysis or stochastic approaches based on a brute-force approach of repeated simulation. Even single deterministic simulations may require parallel high-performance computing. The multiphase flow processes involved are too non-linear for quasi-linear error propagation and other simplified stochastic tools. As an alternative approach, we propose a massive stochastic model reduction based on the probabilistic collocation method. The model response is projected onto a higher-order orthogonal basis of polynomials to approximate dependence on uncertain parameters (porosity, permeability, etc.) and design parameters (injection rate, depth, etc.). This allows for a non-linear propagation of model uncertainty affecting the predicted risk, ensures fast computation, and provides a powerful tool for combining design variables and uncertain variables into one approach based on an integrative response surface. Thus, the design task of finding optimal injection regimes explicitly includes uncertainty, which leads to robust designs with a minimum failure probability. We validate our proposed stochastic approach by Monte Carlo simulation using a common 3D benchmark problem (Class et al., Comput Geosci 13:451–467, 2009). A reasonable compromise between computational efforts and precision was reached already with second-order polynomials. In our case study, the proposed approach yields a significant computational speed-up by a factor of 100 compared with the Monte Carlo evaluation. We demonstrate that, due to the non-linearity of the flow and transport processes during CO₂ injection, including uncertainty in the analysis leads to a systematic and significant shift of the predicted leakage rates toward higher values compared with deterministic simulations, affecting both risk estimates and the design of injection scenarios.     

Bayesian updating via bootstrap filtering combined with data-driven polynomial chaos expansions: methodology and application to history matching for carbon dioxide storage in geological formations

Model calibration and history matching are important techniques to adapt simulation tools to real-world systems. When prediction uncertainty needs to be quantified, one has to use the respective statistical counterparts, e.g., Bayesian updating of model parameters and data assimilation. For complex and large-scale systems, however, even single forward deterministic simulations may require parallel high-performance computing. This often makes accurate brute-force and nonlinear statistical approaches infeasible. We propose an advanced framework for parameter inference or history matching based on the arbitrary polynomial chaos expansion (aPC) and strict Bayesian principles. Our framework consists of two main steps. In step 1, the original model is projected onto a mathematically optimal response surface via the aPC technique. The resulting response surface can be viewed as a reduced (surrogate) model. It captures the model’s dependence on all parameters relevant for history matching at high-order accuracy. Step 2 consists of matching the reduced model from step 1 to observation data via bootstrap filtering. Bootstrap filtering is a fully nonlinear and Bayesian statistical approach to the inverse problem in history matching. It allows to quantify post-calibration parameter and prediction uncertainty and is more accurate than ensemble Kalman filtering or linearized methods. Through this combination, we obtain a statistical method for history matching that is accurate, yet has a computational speed that is more than sufficient to be developed towards real-time application. We motivate and demonstrate our method on the problem of CO₂ storage in geological formations, using a low-parametric homogeneous 3D benchmark problem. In a synthetic case study, we update the parameters of a CO₂/brine multiphase model on monitored pressure data during CO₂ injection.     

Experimental and numerical investigations on CO2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

The feasibility of CO₂ storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO₂ as well as reservoir simulation studies to evaluate the CO₂ wellbore injectivity and displacement efficiency of the residual gas by the injected CO₂. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO₂ has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO₂ injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO₂ gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO₂ volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO₂ will be maximized. The migration/extension of CO₂ varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO₂ extension and pressure propagation suggested no breakthrough of CO₂ at the prospective production well during the 3-year injection period studied.     

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.     

Percolation-theory and fuzzy rule-based probability estimation of fault leakage at geologic carbon sequestration sites

Leakage of CO₂ and displaced brine from geologic carbon sequestration (GCS) sites into potable groundwater or to the near-surface environment is a primary concern for safety and effectiveness of GCS. The focus of this study is on the estimation of the probability of CO₂ leakage along conduits such as faults and fractures. This probability is controlled by (1) the probability that the CO₂ plume encounters a conductive fault that could serve as a conduit for CO₂ to leak through the sealing formation, and (2) the probability that the conductive fault(s) intersected by the CO₂ plume are connected to other conductive faults in such a way that a connected flow path is formed to allow CO₂ to leak to environmental resources that may be impacted by leakage. This work is designed to fit into the certification framework for geological CO₂ storage, which represents vulnerable resources such as potable groundwater, health and safety, and the near-surface environment as discrete “compartments.” The method we propose for calculating the probability of the network of conduits intersecting the CO₂ plume and one or more compartments includes four steps: (1) assuming that a random network of conduits follows a power-law distribution, a critical conduit density is calculated based on percolation theory; for densities sufficiently smaller than this critical density, the leakage probability is zero; (2) for systems with a conduit density around or above the critical density, we perform a Monte Carlo simulation, generating realizations of conduit networks to determine the leakage probability of the CO₂ plume (P _leak) for different conduit length distributions, densities and CO₂ plume sizes; (3) from the results of Step 2, we construct fuzzy rules to relate P _leak to system characteristics such as system size, CO₂ plume size, and parameters describing conduit length distribution and uncertainty; (4) finally, we determine the CO₂ leakage probability for a given system using fuzzy rules. The method can be extended to apply to brine leakage risk by using the size of the pressure perturbation above some cut-off value as the effective plume size. The proposed method provides a quick way of estimating the probability of CO₂ or brine leaking into a compartment for evaluation of GCS leakage risk. In addition, the proposed method incorporates the uncertainty in the system parameters and provides the uncertainty range of the estimated probability.     

An Uncertainty Quantification Framework for Studying the Effect of Spatial Heterogeneity in Reservoir Permeability on CO2 Sequestration

A new uncertainty quantification framework is adopted for carbon sequestration to evaluate the effect of spatial heterogeneity of reservoir permeability on CO₂ migration. Sequential Gaussian simulation is used to generate multiple realizations of permeability fields with various spatial statistical attributes. In order to deal with the computational difficulties, the following ideas/approaches are integrated. First, different efficient sampling approaches (probabilistic collocation, quasi-Monte Carlo, and adaptive sampling) are used to reduce the number of forward calculations, explore effectively the parameter space, and quantify the input uncertainty. Second, a scalable numerical simulator, extreme-scale Subsurface Transport Over Multiple Phases, is adopted as the forward modeling simulator for CO₂ migration. The framework has the capability to quantify input uncertainty, generate exploratory samples effectively, perform scalable numerical simulations, visualize output uncertainty, and evaluate input-output relationships. The framework is demonstrated with a given CO₂ injection scenario in heterogeneous sandstone reservoirs. Results show that geostatistical parameters for permeability have different impacts on CO₂ plume radius: the mean parameter has positive effects at the top layers, but affects the bottom layers negatively. The variance generally has a positive effect on the plume radius at all layers, particularly at middle layers, where the transport of CO₂ is highly influenced by the subsurface heterogeneity structure. The anisotropy ratio has weak impacts on the plume radius, but affects the shape of the CO₂ plume.     

Determining effective wellbore permeability from a field pressure test: a numerical analysis of detection limits

We propose a simple pressure test that can be used in the field to determine the effective permeability of existing wellbores. Such tests are motivated by the need to understand and quantify leakage risks associated with geological storage of CO₂ in mature sedimentary basins. If CO₂ is injected into a deep geological formation, and the resulting CO₂ plume encounters a wellbore, leakage may occur through various pathways in the “disturbed zone” surrounding the well casing. The effective permeability of this composite zone, on the outside of the well casing, is an important parameter for models of leakage. However, the data that exist on this key parameter do not exist in the open literature, and therefore specific field tests need to be done in order to reduce the uncertainty inherent in the leakage estimates. The test designed and analyzed herein is designed to measure effective wellbore permeability within a low-permeability caprock, bounded above and below by permeable reservoirs, by pressurizing the reservoir below and measuring the response in the reservoir above. Alternatively, a modified test can be performed within the caprock without directly contacting the reservoirs above and below. We use numerical simulation to relate pressure response to effective well permeability and then evaluate the range of detection of the effective permeability based on instrument measurement error and limits on fracture pressure. These results can guide field experiments associated with site characterization and leakage analysis.     

Impact of CO<Subscript>2</Subscript> injection rate on heat extraction at the HDR geothermal field of Zhacanggou,China

CO₂ is now considered as a novel heat transmission fluid to extract geothermal energy. It can achieve the goal of energy exploitation and CO₂ geological sequestration. Taking Zhacanggou as research area, a “Three-spot” well pattern (one injection with two production), “wellbore–reservoir” coupled model is built, and a constant injection rate is set up. A fully coupled wellbore–reservoir simulator—T2Well—is introduced to study the flow mechanism of CO₂ working as heat transmission fluid, the variance pattern of each physical field, the influence of CO₂ injection rate on heat extraction and the potential and sustainability of heat resource in Guide region. The density profile variance resulting from temperature differences of two wells can help the system achieve “self-circulation” by siphon phenomenon, which is more significant in higher injection rate cases. The density of CO₂ is under the effect of both pressure and temperature; moreover, it has a counter effect on temperature and pressure. The feedback makes the flow process in wellbore more complex. In low injection rate scenarios, the temperature has a dominating impact on the fluid density, while in high rate scenario, pressure plays a more important role. In most scenarios, it basically keeps stable during 30-year operation. The decline of production temperature is <5 °C. However, for some high injection rate cases (75 and 100 kg/s), due to the heat depletion in reservoir, there is a dramatic decline for production temperature and heat extraction rate. Therefore, a 50-kg/s CO₂ injection rate is more suitable for “Three-spot” well pattern in Guide region.     

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.     

Implications of spatial reservoir uncertainty for CO2 sequestration in the east Snake River Plain, Idaho (USA)

Basalt-hosted hydrogeologic systems have been proposed for geologic CO₂ sequestration based on laboratory research suggesting rapid mineralization rates. However, despite this theoretical appeal, little is known about the impacts of basalt fracture heterogeneity on CO₂ migration at commercial scales. Evaluating the suitability of basalt reservoirs is complicated by incomplete knowledge of in-situ fracture distributions at depths required for CO₂ sequestration. In this work, a numerical experiment is used to investigate the effects of spatial reservoir uncertainty for geologic CO₂ sequestration in the east Snake River Plain, Idaho (USA). Two criteria are investigated: (1) formation injectivity and (2) confinement potential. Several theoretical tools are invoked to develop a field-based approach for geostatistical reservoir characterization and their implementation is illustrated. Geologic CO₂ sequestration is simulated for 10?years of constant-rate injection at ~680,000 tons per year and modeled by Monte Carlo simulation such that model variability is a function of spatial reservoir heterogeneity. Results suggest that the spatial distribution of heterogeneous permeability structures is a controlling influence on formation injectivity. Analysis of confinement potential is less conclusive; however, in the absence of confining sedimentary interbeds within the basalt pile, rapid mineralization may be necessary to reduce the risk of escape.     

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.     

Potential assessment of CO2 geological storage based on injection scenario simulation: A case study in eastern Junggar Basin

Carbon Capture and Storage (CCS) is one of the effective means to deal with global warming, and saline aquifer storage is considered to be the most promising storage method. Junggar Basin, located in the northern part of Xinjiang and with a large distribution area of saline aquifer, is an effective carbon storage site. Based on well logging data and 2D seismic data, a 3D heterogeneous geological model of the Cretaceous Donggou Formation reservoir near D7 well was constructed, and dynamic simulations under two scenarios of single-well injection and multi-well injection were carried out to explore the storage potential and CO₂ storage mechanism of deep saline aquifer with real geological conditions in this study. The results show that within 100 km² of the saline aquifer of Donggou Formation in the vicinity of D7 well, the theoretical static CO₂ storage is 71.967 × 10⁶ tons (P50)^①, and the maximum dynamic CO₂ storage is 145.295 × 10⁶ tons (Case2). The heterogeneity of saline aquifer has a great influence on the spatial distribution of CO₂ in the reservoir. The multi-well injection scenario is conducive to the efficient utilization of reservoir space and safer for storage. Based on the results from theoretical static calculation and the dynamic simulation, the effective coefficient of CO₂ storage in deep saline aquifer in the eastern part of Xinjiang is recommended to be 4.9%. This study can be applied to the engineering practice of CO₂ sequestration in the deep saline aquifer in Xinjiang.     

Exploring the effects of data quality,data worth,and redundancy of CO2 gas pressure and saturation data on reservoir characterization through PEST inversion

This study examined the impacts of reservoir properties on carbon dioxide (CO₂) migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO₂ monitoring data such as spatial–temporal distributions of gas pressure, which can be reasonably monitored in practice. The injection reservoir was assumed to be located 1,400–1,500 m below the ground surface such that CO₂ remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO₂ injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended out 8,000 m from the injection well. The CO₂ migration was simulated using the latest version of the simulator, subsurface transport over multiple phases (the water–salt–CO₂–energy module), developed by Pacific Northwest National Laboratory. A nonlinear parameter estimation and optimization modeling software package, Parameter ESTimation (PEST), is adopted for automated reservoir parameter estimation. The effects of data quality, data worth, and data redundancy were explored regarding the detectability of reservoir parameters using gas pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO₂ monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy. The feasibility of using CO₂ saturation data for improving reservoir characterization was also discussed.     

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.     

A shallow subsurface controlled release facility in Bozeman, Montana, USA, for testing near surface CO2 detection techniques and transport models

A controlled field pilot has been developed in Bozeman, Montana, USA, to study near surface CO₂ transport and detection technologies. A slotted horizontal well divided into six zones was installed in the shallow subsurface. The scale and CO₂ release rates were chosen to be relevant to developing monitoring strategies for geological carbon storage. The field site was characterized before injection, and CO₂ transport and concentrations in saturated soil and the vadose zone were modeled. Controlled releases of CO₂ from the horizontal well were performed in the summers of 2007 and 2008, and collaborators from six national labs, three universities, and the U.S. Geological Survey investigated movement of CO₂ through the soil, water, plants, and air with a wide range of near surface detection techniques. An overview of these results will be presented.     

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise

In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO₂ sequestration benchmark problem entitled “Estimation of the CO₂ Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO₂ distribution within a modeling region, and leakage of CO₂ outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO₂ storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO₂-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO₂ plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO₂ sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence of fractures perpendicular to the dip. Thin shale layers produce stacked CO₂ blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to avoid potential fracturing near injectors.     

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.     

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 %.     

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.