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Geological Storage Group

Geological Storage Group. Michael A. Celia, George W. Scherer, Jean H. Prevost, Jan M. Nordbotten, Catherine Peters, Pablo Debenedeti. Also: Mark Dobossy ( Princeton Univ. ) Sarah Gasda ( Univ. North Carolina ) Stefan Bachu ( Alberta EUB ) Benjamin Court ( Princeton Univ. )

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Geological Storage Group

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  1. Geological Storage Group Michael A. Celia, George W. Scherer, Jean H. Prevost, Jan M. Nordbotten, Catherine Peters, Pablo Debenedeti Also: Mark Dobossy (Princeton Univ.) Sarah Gasda (Univ. North Carolina) Stefan Bachu (Alberta EUB) Benjamin Court (Princeton Univ.) Adam Janzan (Princeton Univ) Tom Elliot (Princeton Univ) Ed Matteo (Princeton Univ.) Zhenhua Sun (Princeton Univ) ImeneGoumiri (Princeton Univ) Matthias Preisig (Princeton Univ)

  2. Four Practical Questions • How much CO2 can be injected? • Rate versus Capacity • How much fluid leaves the injection formation? • CO2 and Brine, Leakage Rates, Leakage Location • Time Scales and Ultimate Fate of CO2 • What is the Area of Review? • How can systems be engineered to improve performance? • Brine management, Water Supply, • Injection Design, …

  3. Processes and Scales Macro Meso Nano Micro Mega (from Nordbotten and Celia, 2010) "Multi-scale Modeling"

  4. Key Information • How much CO2 can be injected? • Fracture Pressure Constraints on Injection Rate • Effective Vertically-Integrated Permeability and Mobility • Boundary Conditions (From Bennion and Bachu, 2008) (From Bennion and Bachu, 2008)

  5. Wabamun Lake, Alberta

  6. Wabamun Lake, Alberta

  7. Layer Properties

  8. Key Information How much fluid leaves the injection formation? Leakage Pathways: Concentrated (Faults, Wells) versus Diffuse (Caprock). Effective Permeability of Well Cements and surrounding materials. Geochemistry of Well Cements. Local-scale (nonisothermal) flows along old wells. Integration of well leakage into large-scale models for CO2 and brine. Dissolution and residual CO2 trapping.

  9. (From Duguid, 2006) Injection and Leakage

  10. Allow acid to attack flat surface of cement paste from one direction Use time-lapse video to determine kinetics Profile corroded sample Composition by environmental SEM Strength by micro-indentation Porosity & Diffusivity by NMR (w/Dr Leo Pel in Eindhoven) Validate & upgrade corrosion model (w/Dr Bruno Huet, Schlumberger) Uniaxial Corrosion Studies

  11. Cement in tube is corroded by acid on surface Time-lapse movie made using USB microscope Uniaxial Corrosion Kinetics

  12. Cement in tube is corroded by acid on surface Time-lapse movie made using USB microscope Uniaxial Corrosion Kinetics

  13. Initial attack controlled by diffusion Long-term rate decreases Pore blocking by carbonate? t ~ 0 hrs t = 10 hrs t = 20 hrs t = 30 hrs t = 40 hrs t = 50 hrs Corrosion Rate Cement Corrosion Acid

  14. Using high enough flow rate leads to pure diffusion control Slowing observed in batch experiments may result from accumulation of products on surface Rate of loss of surface may indicate contraction of gel Would open annular gap Corrosion Rate

  15. Negligible effect on corrosion kinetics Some change in layer structure Property profiles not yet quantified Composition Strength Pore size distribution Diffusivity 1 M HCl, 0.5 M NaCl 1 M HCl t= 24 hrs 1 M HCl, 0.5 M NaCl 1 M HCl t= 48 hrs Effect of salt

  16. Simulator created by Jean-Hervé Prévost Fluid transport fully coupled with geomechanics (poromechanics) Reactive transport capabilities for cement attack/degradation by CO2 Equation of state - based flash Heat transfer Unique capability to predict phase changes (e.g. boiling of CO2) Essential for modeling of leakage as carbonated brine rises in crack Dynaflow Fully coupled simulator

  17. Test system initially contains of 50% water and 50% CO2 in equilibrium at T = 15˚C Temperature of left boundary is raised to T = 125˚C As temperature rises, water boils Where does the transition occur? How much of each phase is present? How does the phase change affect the transport rate? Liquid Vapor EOS flash test: 2 components, 3 phases P T

  18. Ability to predict phase changes is essential step toward modeling leaks Next step is to include corrosion with flow and phase change Successful solution of test case Gas Liquid CO2 Aqueous Solution

  19. Natural CO2 geysers produce violent eruptions Mechanism previously not understood Simulations demonstrate that rapid leak causes freezing of formation water, which blocks CO2 flow Flow resumes after heat from formation melts the ice plug Predictions match observed frequency of eruptions CO2 Geysers Crystal Geyser, Utah

  20. Long-term Predictions hr time hc ω H slope From: Gasda et al., 2010

  21. Long-term Predictions From: Nordbotten and Celia, 2010; Gasda et al., 2010

  22. Long-term Predictions Advancement of dissolution fingers (Riaz et al. 05)

  23. Long-term Predictions

  24. Numerical results of residual and solubility trapping in the Johansen formation during a 3,000-year post-injection period. The colored scale shows porosity. The contours indicate the outer edge of the different CO2 regions (mobile, residual, dissolved) within the subregion indicated in the figure. Results from Gasda et al., 2010.

  25. Long-term Predictions Free-phase CO2 Residual CO2 Dissolved CO2

  26. Key Information • What is the Area of Review? • Follows EPA UIC Approach. • Determined by pressure perturbations, not CO2 plume. • Diffuse leakage becomes important. • Boundary conditions are likely to be important. • How can systems be engineered to improve performance? • Design Injection wells to minimize (1) pressure at wells and (2) Area of Review. • Extract brine to manage pressure, provide water for surface facilities.

  27. New Projects related to CCS • EPA: A Hierarchical Modeling Framework for Geological Storage of Carbon Dioxide • PI: M. Celia • We will develop a hierarchy of models, from simple to complex, to model CO2, brine, and pressure behavior, with a focus on CO2 and brine leakage and definition of area of review • We will also develop simple web-based interfaces for different versions of our models. • This will be a collaborative agreement with EPA so we will work directly with researchers from EPA research lab in Athens, Georgia. • NSF: Advanced Computational Models for Geological Storage of Carbon Dioxide • Lead PI: M. Celia (with H. Wang from USC) • Combine advanced numerical methods (ELLAM) in an Elsa/VESA framework • DOE (1): Analytical-Numerical Sharp Interface Model of CO2 Sequestration and Application to Illinois Basin • Lead PI: Mark Person, New Mexico Tech • Princeton will add a saltwater-freshwater interface to the Elsa model, include a sub-scale model for leakage along faults, andparticipate in modeling of the Illinois Basin. • New Mexico Tech, Princeton, Illinois Geol Survey, Indiana University, Los Alamos.

  28. New Projects related to CCS • DOE (2): Quantification of Wellbore Leakage Risk using Nondestructive Borehole Logging Techniques • Lead PI: Andrew Duguid, Schlumberger • Princeton will perform data analysis and develop software for parameter estimation. • Schlumberger, Los Alamos, and Princeton • DOE (3): Basin-Scale Leakage Risks from Geologic Carbon Sequestration: Impact on CCS Energy Market Competitiveness • Lead PI: Catherine Peters, Princeton • Our group will apply the Elsa code to model the Michigan Basin. We may also contribute to efforts to couple Else to geochemical reaction models. • Princeton, University of Minnesota, Brookhaven Natl. Lab. • DOE (4): Upscaling Geochemical Reaction Rates for CO2 in Deep Saline Aquifers • Lead PI: Catherine Peters, Princeton • NSF: DUSEL - Large-scale field experiments • Lead PI: Catherine Peters, Princeton

  29. Thank You!

  30. Celia, M.A., J.M. Nordbotten, B. Court, M. Dobossy, and S. Bachu, “Field-scale Application of a Semi-analytical Model for Estimation of Leakage Potential along Old Wells”, under review, Int. J. Greenhouse Gas Technologies, 2010. Gasda, S.E., J.M. Nordbotten, and M.A. Celia, “Vertically-averaged Approaches for CO2 Injection with Solubility Trapping”, under review, Water Resources Research, 2010. Celia, M.A. and J.M. Nordbotten, "Practical Modeling Approaches for Geological Storage of Carbon Dioxide", Ground Water, 47(5), 627-638, 2009. Gasda, S.E., J.M. Nordbotten, and M.A. Celia, "Vertical Equilibrium with Sub-scale Analytical Methods for Geological CO2 Sequestration", Computational Geosciences, published online 23 April 2009. Nordbotten, J.M., D. Kavetski, M.A. Celia, S. Bachu, “Model for CO2 Leakage including Multiple Geological Layers and Multiple Leaky Wells”, Environmental Science and Technology, 43(3), 743-749, 2009. Celia, M.A., J.M. Nordbotten, S. Bachu, M. Dobossy, and B. Court, "Risk of Leakage versus Depth of Injection in Geological Storage", Proc. GHGT-9, Washington, DC, November 2008. Gasda, S., J.M. Nordbotten, and M.A. Celia, "Upslope Plume Migration and Implications for Geological CO2 Storage in Deep Saline Aquifers", IES Journal of Civil Engineering, Vol. 1, No. 1, page 1, 2008. Gasda, S., J.M. Nordbotten, and M.A. Celia, "Determining Effective Wellbore Permeability from a Field Pressure Test: A numerical Analysis of Detection Limits", Environmental Geology, 54(6), 1207-1215, 2008. Nordbotten, J.M. and M.A. Celia, "Similarity Solutions for Fluid Injection into Confined Aquifers", Journal of Fluid Mechanics, 561, 307-327, 2006. Publications

  31. Current Modeling • Injection Period: Elsa Version 1.0 • Injection and leakage including multiple layers and multiple wells. • Expanding to hybrid numerical-analytical framework. • Diffuse leakage in pressure responses. • Post-injection Period • Large-scale (upscaled) dissolution and convective mixing • Inclusion of capillary fringe – expansion of sharp interface still with vertical equilibrium

  32. Current Modeling • All Models are in a Multi-scale Framework • Vertical Integration with Dupuit Assumption as a Compression Operator. • Reconstructed Phase Pressures with assumption of Gravity Segregation. • Saturation Reconstruction based on capillary equilibrium and local-scale Pc-S relationships.

  33. Additional Activities • Continuing work with Walter Crow (BP Houston) and others (Schlumberger/DOE) on well measurement program. • Continuing interactions with Norwegian colleagues. • Development of more general numerical-analytical hybrid models for multi-layer systems. • Development of simple web-based interfaces for Elsa-type simulations. • Applications to Illinois Basin and Michigan Basin, as well as continuing applications to Alberta Basin. • Interactions with LBL, EPA, NMT, LANL, Sintef, CIPR, others on simulation strategies.

  34. Simplified models can be reasonable because: Buoyancy provides strong vertical segregation Space- and time-scale separation for critical processes Large uncertainties in critical leakage parameters make detailed fine-scale simulation of marginal value. Multi-scale Framework allows for: Reduction of computational requirements Full 3-D resolution with reconstruction of pressures and saturations Overall, the carbon problem can only be solved by very large efforts, and CCS is likely to be a central technology. Concluding Remarks

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