Numerical Modeling Studies of The Dissolution-Diffusion-Convection ProcessDuring CO2 Storage in Saline Aquifers

Pruess, Karsten; Zhang, Keni

doi:10.2172/944124

Cited by 79 publications

(102 citation statements)

References 18 publications

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“…Numerical studies of brine convection (Pruess and Zhang 2008) using much finer grid resolution than this study indicate that the details of convection (e.g., how many convection Fig. 19 East-west cross-section of the dissolved CO 2 plume at a series of times for sensitivity-study Case SH4, shown by plotting X CO 2L , mass fraction of CO 2 in the aqueous phase, in the plane y = 0.…”

Section: Shale Vertical Permeability Studiesmentioning

confidence: 81%

“…For a typical CO 2 diffusivity of D = 2 . 10 −9 m 2 /s (Pruess and Zhang 2008), the characteristic diffusion length (Dt) 1/2 is only 0. 5 m for 4 years, 2.5 m for 100 years, and 8 m for 1,000 years, all small compared to CO 2 plume dimensions.…”

Section: Numerical Simulatormentioning

confidence: 99%

“…In fact, CO 2 -saturated brine is denser than native brine. As CO 2 -laden brine sinks deeper into the formation, it can set up circulation patterns that enable more free-phase CO 2 to come into contact with native brine, enabling more dissolution to occur (Ennis-King and Paterson 2005;Pruess and Zhang 2008). (4) Mineral trapping: CO 2 reacts with rock minerals to form carbonate compounds, typically over very long time scales Xu et al 2003Xu et al , 2005Gherardi et al 2007).…”

Section: Fig 1 Map Of California Showing Potential Geologic Carbon Smentioning

confidence: 99%

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Investigation of CO2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

2009

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The hydrodynamic behavior of carbon dioxide (CO 2 ) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO 2 plume stabilization. A numerical model of the subsurface at a proposed power plant with CO 2 capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO 2 is injected over a 4-year period, and the subsequent evolution of the CO 2 plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO 2 between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO 2 plume is effectively immobilized at 25 years. At that time, 38% of the CO 2 is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical, and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint, but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual CO 2 saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs between different trapping mechanisms.

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Section: Shale Vertical Permeability Studiesmentioning

confidence: 81%

Section: Numerical Simulatormentioning

confidence: 99%

Section: Fig 1 Map Of California Showing Potential Geologic Carbon Smentioning

confidence: 99%

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Investigation of CO2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

2009

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“…The top boundary is saturated with dissolved CO 2 . The configuration is widely used for validation and comparison of CO 2 -sequestration modeling (Pruess and Zhang 2008;Pau et al 2010;Allen and Sun 2012).…”

Section: Resultsmentioning

confidence: 99%

“…With this configuration and concentration on the top boundary constant over time, the quantity of CO 2 that diffuses into the underlying fluid can be computed analytically with a complementary error function (Pruess and Zhang 2008;Clark 2009;Allen and Sun 2012). With this function, the concentration with distance y from the boundary at time t can be evaluated as…”

Section: Resultsmentioning

confidence: 99%

High-Performance Modeling of Carbon Dioxide Sequestration by Coupling Reservoir Simulation and Molecular Dynamics

Bao

Yan²,

Allen

et al. 2016

SPE Journal

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SummaryThe present work describes a parallel computational framework for carbon dioxide (CO 2 ) sequestration simulation by coupling reservoir simulation and molecular dynamics (MD) on massively parallel high-performance-computing (HPC) systems. In this framework, a parallel reservoir simulator, reservoir-simulation toolbox (RST), solves the flow and transport equations that describe the subsurface flow behavior, whereas the MD simulations are performed to provide the required physical parameters. Technologies from several different fields are used to make this novel coupled system work efficiently.One of the major applications of the framework is the modeling of large-scale CO 2 sequestration for long-term storage in subsurface geological formations, such as depleted oil and gas reservoirs and deep saline aquifers, which has been proposed as one of the few attractive and practical solutions to reduce CO 2 emissions and address the global-warming threat. Fine grids and accurate prediction of the properties of fluid mixtures under geological conditions are essential for accurate simulations. In this work, CO 2 sequestration is presented as a first example for coupling reservoir simulation and MD, although the framework can be extended naturally to the full multiphase multicomponent compositional flow simulation to handle more complicated physical processes in the future.Accuracy and scalability analysis are performed on an IBM BlueGene/P and on an IBM BlueGene/Q, the latest IBM supercomputer. Results show good accuracy of our MD simulations compared with published data, and good scalability is observed with the massively parallel HPC systems. The performance and capacity of the proposed framework are well-demonstrated with several experiments with hundreds of millions to one billion cells.To the best of our knowledge, the present work represents the first attempt to couple reservoir simulation and molecular simulation for large-scale modeling. Because of the complexity of subsurface systems, fluid thermodynamic properties over a broad range of temperature, pressure, and composition under different geological conditions are required, although the experimental results are limited. Although equations of state can reproduce the existing experimental data within certain ranges of conditions, their extrapolation out of the experimental data range is still limited. The present framework will definitely provide better flexibility and predictability compared with conventional methods.

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The study of heterogeneous two‐phase flow around small‐scale heterogeneity in porous sandstone by measured elastic wave velocities and lattice Boltzmann method simulation

et al. 2014

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Two-phase fluid flow is strongly controlled by small-scale (subcore-scale) heterogeneity of porous sandstone. We monitor the heterogeneous/anisotropic two-phase flow (CO 2 and water) in porous sandstone and conduct multichannel V P and V P anisotropy measurements under super critical CO 2 conditions during CO 2 injection (drainage) and water reinjection (imbibition) processes. In drainage, V P shows large reduction (~10%) in all sections of the core sample and changes from the bottom inlet side to upper outlet side. It is considered that V P reduction reflects the CO 2 movement in the specimen. The V P anisotropy of the upper two planes indicates clear increase. The results of this experiment indicate the heterogeneous CO 2 flow around laminae in porous sandstone and characteristic behavior of these laminae as a barrier for CO 2 . On the other hand, flow of water is not affected by this barrier. This characteristic CO 2 water flow around laminae is observed in the numerical simulation results. This simulation study also indicates that the capillary number is not directly affected on two-phase fluid flow around small-scale heterogeneity in porous sandstone. These results suggest that the small-scale heterogeneity behaves as a CO 2 gate and strongly controls CO 2 behavior in porous sandstone.It is well known that fluid flow in porous sandstone is strongly affected by small-scale heterogeneity of sedimentary structures (millimeter to centimeter scale). In the case of multiphase fluid flow (e.g., N 2 , CO 2 , and brine), the nonwetting phase fluid (N 2 and CO 2 ) can show complex behavior. Recent studies have successfully KITAMURA ET AL. Key Points: • The gate effect of small-scale heterogeneity on CO 2 flow in porous sandstone • Monitoring of anisotropic CO 2 flow around lamina by V P and V P anisotropy • Water and CO 2 flow simulation by LBM in heterogeneous sandstone

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Numerical Modeling Studies of The Dissolution-Diffusion-Convection ProcessDuring CO2 Storage in Saline Aquifers

Cited by 79 publications

References 18 publications

Investigation of CO2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

Investigation of CO2 Plume Behavior for a Large-Scale Pilot Test of Geologic Carbon Storage in a Saline Formation

High-Performance Modeling of Carbon Dioxide Sequestration by Coupling Reservoir Simulation and Molecular Dynamics

The study of heterogeneous two‐phase flow around small‐scale heterogeneity in porous sandstone by measured elastic wave velocities and lattice Boltzmann method simulation

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