An improved brine-relative permeability model with hysteresis and its significance to sequestrated CO2 in a deep saline aquifer

  • R. Vivek
  • G. Suresh KumarEmail author
Original Article


Relative permeability is the fundamental petrophysical property that governs the flow and distribution of sequestrated CO2 in a deep saline aquifer, which conceptually has implications on the dissolution and capillary trapping mechanisms. The significance of trapped-gas saturation on the imbibition-relative permeability of wetting brine phase has been less emphasized in the literature. Numerically computing the hysteretic brine-relative permeability at every nodal point corresponding to the wetting phase saturation (saturation history) is a challenge. Whereas, the complexity is associated with computing the endpoint-relative permeability of brine phase corresponding to the wetting phase saturation at which flow reversal is taking place. In the present paper, an improved hysteresis-relative permeability model for wetting brine phase using Land’s trapping coefficient has been presented. The present relative permeability model has been validated using the experimental results from the literature. The sensitivity of considering hysteresis brine-relative permeability on flow and distribution of sequestrated CO2 in a deep saline aquifer has been numerically investigated. The observed results emphasize that the flow model, without considering the brine-relative permeability hysteresis, over-predicts the distribution of sequestrated CO2 in the system of porous medium considered.


CO2 sequestration Deep saline aquifer Capillary trapping Brine-relative permeability hysteresis 



  1. Al-Khdheeawi EA, Vialle S, Barifcani A, Sarmadivaleh M, Iglauer S (2017) Impact of reservoir wettability and heterogeneity on CO2-plume migration and trapping capacity. Int J Greenh Gas Control 58, 142–158. CrossRefGoogle Scholar
  2. Bachu S, Bennion B (2008) Effects of in-situ conditions on relative permeability characteristics of CO2-brine systems. Environ Geol 54:1707–1722. CrossRefGoogle Scholar
  3. Bear J, Cheng A-D (2010) Modeling groundwater flow and contaminant transport. Springer Science & Business MediaGoogle Scholar
  4. Bennion DB, Bachu S (2006) Dependence on temperature, pressure, and salinity of the IFT and relative permeability displacement characteristics of CO2 injected in deep saline aquifers. In: SPE-102138-MS. Society of Petroleum Engineers.
  5. Buckley SE, Leverett MC (1942) Mechanism of Fluid Displacement in Sands. Trans AIME 146:107–116. CrossRefGoogle Scholar
  6. Duan Z, Sun R, Zhu C, Chou IM (2006) An improved model for the calculation of CO2 solubility in aqueous solutions containing Na+, K+, Ca2+, Mg2+, Cl, and SO42−. Mar Chem 98:131–139. CrossRefGoogle Scholar
  7. Fatemi SM, Sohrabi M (2018) Relative permeabilities hysteresis for oil/water, gas/water and gas/oil systems in mixed-wet rocks. J Pet Sci Eng 161:559–581. CrossRefGoogle Scholar
  8. Gasda SE (2008) Numerical models for evaluating carbon dioxide storage in deep, saline aquifers: leaky wells and large-scale geological features. Princeton University, Ann ArborGoogle Scholar
  9. Hassanzadeh H, Pooladi-Darvish M, Elsharkawy AM, Keith DW, Leonenko Y (2008) Predicting PVT data for CO2–brine mixtures for black-oil simulation of CO2 geological storage. Int J Greenh Gas Control 2:65–77. CrossRefGoogle Scholar
  10. Hassanzadeh H, Pooladi-Darvish M, Keith DW (2009) Accelerating CO2 dissolution in saline aquifers for geological storage: Mechanistic and sensitivity studies. Energy Fuels 23:3328–3336. CrossRefGoogle Scholar
  11. Iglauer S (2011) Dissolution trapping of carbon dioxide in reservoir formation brine—a carbon storage mechanism. INTECH Open Access PublisherGoogle Scholar
  12. IPCC (2014) Climate Change 2014 Synthesis Report Summary Chapter for Policymakers. Ipcc 31.
  13. Juanes R, Spiteri EJ, Orr FM, Blunt MJ (2006) Impact of relative permeability hysteresis on geological CO2 storage. Water Resour Res 42.
  14. Juanes R, MacMinn CW, Szulczewski ML (2009) The footprint of the CO2 plume during carbon dioxide storage in saline aquifers: storage efficiency for capillary trapping at the basin scale. Transp Porous Media 82:19–30. CrossRefGoogle Scholar
  15. Killough JE (1976) Reservoir simulation with history-dependent saturation functions. Soc Pet Eng J 16:37–48. CrossRefGoogle Scholar
  16. Krevor S, Blunt MJ, Benson SM, Pentland CH, Reynolds C, Al-Menhali A, Niu B (2015) Capillary trapping for geologic carbon dioxide storage – From pore scale physics to field scale implications. Int J Greenh Gas Control 40:221–237. CrossRefGoogle Scholar
  17. Land CS (1968) Calculation of imbibition relative permeability for two-and three-phase flow from rock properties. Soc Pet Eng J 8:149–156. CrossRefGoogle Scholar
  18. Nordbotten JM, Celia MA (2011) Geological storage of CO2: modeling approaches for large-scale simulation, geological storage of CO.
  19. Osoba JS, Richardson JG, Kerver JK, Hafford JA, Blair PM (1951) Laboratory measurements of relative permeability. Pet Trans AIME 192.
  20. Vivek R, Kumar GS (2016) Numerical investigation on effect of varying injection scenario and relative permeability hysteresis on CO2 dissolution in saline aquifer. Environ Earth Sci 75.
  21. Vivek R, Sivasankar P, Suresh Kumar G (2017) Accelerating dissolution trapping by low saline WAG injection scenario. Energy Procedia 114:5038–5047. CrossRefGoogle Scholar

Copyright information

© Springer-Verlag GmbH Germany, part of Springer Nature 2019

Authors and Affiliations

  1. 1.Petroleum Engineering Program, Department of Ocean EngineeringIndian Institute of Technology MadrasChennaiIndia

Personalised recommendations