Research Papers: Fundamental Issues and Canonical Flows

Microfluidics Underground: A Micro-Core Method for Pore Scale Analysis of Supercritical CO2 Reactive Transport in Saline Aquifers

[+] Author and Article Information
David Sinton

e-mail: sinton@mie.utoronto.ca
Department of Mechanical and Industrial Engineering and Institute for Sustainable Energy,
University of Toronto,
5 King's College Road,
Toronto, ON, M5S 3G8, Canada

1Corresponding author.

Manuscript received August 5, 2012; final manuscript received December 13, 2012; published online March 19, 2013. Assoc. Editor: Kendra Sharp.

J. Fluids Eng 135(2), 021203 (Mar 19, 2013) (7 pages) Paper No: FE-12-1366; doi: 10.1115/1.4023644 History: Received August 05, 2012; Revised December 13, 2012

Carbon sequestration in microporous geological formations is an emerging strategy for mitigating CO2 emissions from fossil fuel consumption. Injection of CO2 in carbonate reservoirs can change the porosity and permeability of the reservoir regions, along the CO2 plume migration path, due to CO2-brine-rock interactions. Carbon sequestration is effectively a microfluidic process over large scales, and can readily benefit from microfluidic tools and analysis methods. In this study, a micro-core method was developed to investigate the effect of CO2 saturated brine and supercritical CO2 injection, under reservoir temperature and pressure conditions of 8.4 MPa and 40 °C, on the microstructure of limestone core samples. Specifically, carbonate dissolution results in pore structure, porosity, and permeability changes. These changes were measured by X-ray microtomography (micro-CT), liquid permeability measurements, and chemical analysis. Chemical composition of the produced liquid analyzed by inductively coupled plasma-atomic emission spectrometer (ICP-AES) shows concentrations of magnesium and calcium in the produced liquid. Chemical analysis results are consistent with the micro-CT imaging and permeability measurements which all show high dissolution for CO2 saturated brine injection and very minor dissolution under supercritical CO2 injection. This work leverages established advantages of microfluidics in the new context of core-sample analysis, providing a simple core sealing method, small sample size, small volumes of injection fluids, fast characterization times, and pore scale resolution.

Copyright © 2013 by ASME
Your Session has timed out. Please sign back in to continue.


Weibel, D. B., and Whitesides, G. M., 2006, “Applications of Microfluidics in Chemical Biology,” Current Opin. Chem. Biol., 10, pp. 584–591. [CrossRef]
Stone, H. A., Strook, A. D., and Ajdari, A., 2004, “Engineering Flows in Small Devices: Microfluidics Toward a Lab-on-a-Chip,” Annu. Rev. Fluid Mech., 36, pp. 381–411. [CrossRef]
Berejnov, V., Djilali, N., and Sinton, D., 2008, “Lab-on-Chip Methodologies for the Study of Transport in Porous Media: Energy Applications,” Lab Chip, 8, pp. 689–693. [CrossRef] [PubMed]
Fadaei, H., Scarff, B., and Sinton, D., 2011, “Rapid Microfluidic-Based Measurement of CO2 Diffusivity in Bitumen,” Energy Fuels, 25, pp. 4829–4835. [CrossRef]
Gunda, N. S. K., Bera, B., Karadimitriou, N. K., Mitra, S. K., and Hassanizadeh, S. M., 2011, “Reservoir-on-a-Chip (ROC): A New Paradigm in Reservoir Engineering,” Lab Chip, 11, pp. 3785–3792. [CrossRef] [PubMed]
Riazi, M., Sohrabi, M., Bernstone, C., Jamiolahmady, M., and Ireland, S., 2011, “Visualization of Mechanisms Involved in CO2 Injection and Storage in Hydrocarbon Reservoir Water Bearing Aquifers,” Chem. Eng. Res. Design, 89, pp. 1827–1840. [CrossRef]
Sok, R. M., Varslot, T., Ghous, A., Latham, S., Sheppard, A. P., and Knackstedt, M. A., 2009, “Pore Scale Characterization of Carbonates at Multiple Scales: Integration of Micro-CT, BSEM, and FIBSEM,” Petrophysics International Symposium of the Society-of-Core-Analysts, Noordwijk, The Netherlands, Sept. 27–30.
Dong, H., and Blunt, M. J., 2009, “Pore-Network Extraction From Micro-Computerized-Tomography Images,” Phys. Rev. E, 80, p. 036307. [CrossRef]
Bachu, S., and Adams, J. J., 2003, “Sequestration of CO2 in Geological Media in Response to Climate Change: Capacity of Deep Saline Aquifers to Sequester CO2 in Solution,” Energy Conversion and Management, 44, pp. 3151–3175. [CrossRef]
Bradshaw, J., Bachu, S., Bonijoly, D., Burruss, R., Holloway, S., Christensen, N. P., and Mathiassen, O. M., 2007, “CO2 Storage Capacity Estimation: Issues and Development Of Standards,” Int. J. Greenhouse Gas Control, 1, pp. 62–68. [CrossRef]
Bachu, S., 2008, “CO2 Storage in Geological Media: Role, Means, Status, and Barriers to Deployment,” Prog. Energy Combust. Sci., 34, pp. 254–273. [CrossRef]
Diamond, L. W., and Akinfiev, N., 2003, “Solubility of CO2 in Water From −1.5 to 100 °C and From 0.1 to 100 MPa: Evaluation of Literature Data and Thermodynamic Modeling,” Fluid Phase Equilibria, 208, pp. 265–290. [CrossRef]
Duan, Z., and Sun, R., 2003, “An Improved Model Calculating CO2 Solubility in Pure Water and Aqueous NaCl Solutions From 273 to 553K and From 0 to 2000 bar,” Chem. Geol., 193, pp. 257–271. [CrossRef]
Plummer, L. N., Wigley, T. M. L., and Parkhurst, D. L., 1978, “The Kinetics of Calcite Dissolution in CO2-Water Systems at 5 to 60 °C and 0.0 to 1.0 atm CO2,” Am. J. Sci., 278, pp. 179–216. [CrossRef]
Pokrovsky, O. S., Golubev, S. V., Schott, J., and Castillo, A., 2009, “Calcite, Dolomite, and Magnesite Dissolution Kinetics in Aqueous Solutions at Acid to Circumneutral pH, 25 to 150 °C and 1 to 55 atm pCO2: New Constraints on CO2 Sequestration in Sedimentary Basins,” Chem. Geol., 265, pp. 20–32. [CrossRef]
Izgec, O., Demiral, B., Bertin, H., and Akin, S., 2008, “CO2 Injection Into Saline Carbonate Aquifer Formations I: Laboratory Investigation,” Transport Porous Media, 72, pp. 1–24. [CrossRef]
Perrin, J. C., Krause, M., Kuo, C. W., Miljkovic, L., Charoba, E., and Benson, S. M., 2009, “Core-Scale Experimental Study of Relative Permeability Properties of CO2 and Brine in Reservoir Rocks,” Energy Procedia, 1, pp. 3515–3522. [CrossRef]
Luquot, L., and Gouze, P., 2009, “Experimental Determination of Porosity and Permeability Changes Induced by Injection of CO2 into Carbonate Rocks,” Chem. Geol., 265, pp. 148–159. [CrossRef]
Gouze, P., and Luquot, L., 2011, “X-Ray Microtomography Characterization of Porosity, Permeability and Reactive Surface Changes During Dissolution,” J. Contaminant Hydrology, 120–121, pp. 45–55. [CrossRef]
Iglauer, S., Paluszny, A., Pentland, C. H., and Blunt, M., 2011, “Residual CO2 Imaged With X-Ray Micro-Tomography,” Geophys. Res. Lett., 38, p. L21403. [CrossRef]
Noiriel, C., Gouze, P., and Bernard, D., 2004, “Investigation of Porosity and Permeability Effects From Microstructure Changes During Limestone Dissolution,” Geophys. Res. Lett., 31, p. L24603. [CrossRef]
Bennion, D. B., and Bachu, S., 2010, “Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for High-Permeability Carbonate Rocks,” Society of Petroleum Engineers (SPE), ID No. 134028. [CrossRef]
Pruess, K., and Nordbotten, J., 2011, “Numerical Simulation Studies of the Long-Term Evolution of a CO2 Plume in a Saline Aquifer With a Sloping Caprock,” Transp. Porous Med., 90, pp. 135–151. [CrossRef]
Sen, D., Nobes, D. S., and Mitra, S. K., 2012, “Optical Measurement of Pore Scale Velocity Field Inside Microporous Media,” Microfluid Nanofluid, 12, pp. 189–200. [CrossRef]
Grigg, R. B., Svec, R. K., Lichtner, P. C., Carey, W., and Lesher, C. E., 2005, “CO2/Brine/Carbonate Rock Interactions: Dissolution and Precipitation,” 4th Annual Conference on Carbon Capture and Sequestration, Alexandria, VA, pp. 1–14.


Grahic Jump Location
Fig. 1

Schematic of the experimental setup for the micro-core flooding experiments with pure CO2 and CO2 saturated brine. The system uses a microfluidic chip style holder and connections which simplify the apparatus as compared to conventional core-study methods. The parts inside the dotted line were kept at constant temperature of 40 °C in a water bath. An image of the micro-core is shown inset.

Grahic Jump Location
Fig. 2

SEM images of Indiana limestone core samples used in this study (a) intergranular pores; (b) intragranular pores of the dotted red line region in part (a). For both cases, the black areas are pores and gray areas are grains. Scale bars indicate 500 μm in (a) and 10 μm in (b).

Grahic Jump Location
Fig. 3

Pore structure changes due to CO2-saturated brine injection for 3 h (a) before CO2 injection; (b) after CO2 injection; (c) binary image conversion from gray image and histogram. Coronal plane is the horizontal plane, sagittal plane is the vertical plane, and transaxial plane is the axial plane. The image resolution is 4.9 μm per pixel. Black areas are pores and gray areas are grains. The degree of dissolution is significant, with a porosity increase from 18.1% to 26.8% and an observable increase in pore connectivity.

Grahic Jump Location
Fig. 4

Pore structure changes due to pure CO2 injection through the core for 3 h (a) before CO2 injection; (b) after CO2 injection. Coronal plane is the horizontal plane, sagittal plane is the vertical plane, and transaxial plane is the axial plane. The image resolution is 4.9 μm per pixel. Black areas are pores and gray areas are grain. In comparison with CO2-saturated brine flooding (Fig. 3), very little dissolution occurs in this case. Porosity increase is minor, from 17.5% to 19.5%.

Grahic Jump Location
Fig. 5

Pressure drop across the core at each flow rate for permeability calculations before and after core flooding for 3 h at reservoir conditions of 8.4 MPa and 40 °C. (a) CO2-saturated brine core flooding. The linear fit of the flow rate versus pressure drop correlation R2 value is 0.999 for before and 0.996 for after core flooding. (b) ScCO2 core flooding. The linear fit of the flow rate versus pressure drop correlation R2 value is 0.993 for before and 0.966 for after core flooding.

Grahic Jump Location
Fig. 6

Chemical analysis of the produced liquid showing both the Ca2+ and Mg2+ ion concentrations over time. (a) Ca2+ ion concentrations in the produced liquid measured with ICP-AES over the 3 h core flooding experiments with CO2-saturated brine and pure scCO2. (b) Mg2+ ion concentrations in the produced liquid measured with ICP-AES over the 3 h core flooding experiments with CO2-saturated brine and pure scCO2.




Some tools below are only available to our subscribers or users with an online account.

Related Content

Customize your page view by dragging and repositioning the boxes below.

Related Journal Articles
Related eBook Content
Topic Collections

Sorry! You do not have access to this content. For assistance or to subscribe, please contact us:

  • TELEPHONE: 1-800-843-2763 (Toll-free in the USA)
  • EMAIL: asmedigitalcollection@asme.org
Sign In