Simulation of CO2 storage in saline aquifers

S. Ghanbari, Y. Al-Zaabi, G. E. Pickup, Eric Mackay, F. Gozalpour, A. C. Todd

    Research output: Contribution to journalArticle

    Abstract

    This paper evaluates key parameters in CO2 storage in saline aquifers. A reservoir simulator was used to simulate 30 years of CO2 injection followed by 470 years of shut in. Two retention mechanisms were modelled: hydrodynamic and solubility trapping. Solubility trapping was found to be the most important means for storing CO2. This effect was enhanced by the creation of convective flow patterns which lead to a greater dissolution Of CO2. Tests were carried out on a homogeneous model, and the effects of CO2 diffusion in brine, vertical to horizontal permeability ratio, residual saturations, salinity and injection well completion interval were investigated. Results were compared with those from other studies to develop a more general understanding of factors affecting CO2 storage. To increase the realism of this study, the effect of geological heterogeneity was also examined. Three types of heterogeneity were investigated: low level random variations in sandstone permeability, stochastic shale layers and a fault. The low level heterogeneity did not have a large effect, although it distorted the convective pattern, while the presence of shales did have a large effect. CO2 tends to become trapped beneath the shale layers increasing the lateral migration. The amount of dissolved CO2 was largest in the models with an intermediate amount of shale. It was found that the fault did not affect the pressure distribution in the aquifer, unless the transmissibility was very low. However, the distribution of CO2 was affected by the location of the well relative to the fault. © 2006 Institution of Chemical Engineers.

    Original languageEnglish
    Pages (from-to)764-775
    Number of pages12
    JournalChemical Engineering Research and Design
    Volume84
    Issue number9 A
    DOIs
    Publication statusPublished - Sep 2006

    Fingerprint

    aquifer
    shale
    simulation
    trapping
    solubility
    permeability
    well completion
    flow pattern
    brine
    simulator
    hydrodynamics
    dissolution
    effect
    sandstone
    saturation
    salinity
    distribution

    Keywords

    • CCS
    • CO 2 storage
    • Convection
    • Geological heterogenity
    • Resevoir simulation
    • Saline aquifers
    • Sensitivity studies

    Cite this

    Ghanbari, S. ; Al-Zaabi, Y. ; Pickup, G. E. ; Mackay, Eric ; Gozalpour, F. ; Todd, A. C. / Simulation of CO2 storage in saline aquifers. In: Chemical Engineering Research and Design. 2006 ; Vol. 84, No. 9 A. pp. 764-775.
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    Simulation of CO2 storage in saline aquifers. / Ghanbari, S.; Al-Zaabi, Y.; Pickup, G. E.; Mackay, Eric; Gozalpour, F.; Todd, A. C.

    In: Chemical Engineering Research and Design, Vol. 84, No. 9 A, 09.2006, p. 764-775.

    Research output: Contribution to journalArticle

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    AU - Ghanbari, S.

    AU - Al-Zaabi, Y.

    AU - Pickup, G. E.

    AU - Mackay, Eric

    AU - Gozalpour, F.

    AU - Todd, A. C.

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    AB - This paper evaluates key parameters in CO2 storage in saline aquifers. A reservoir simulator was used to simulate 30 years of CO2 injection followed by 470 years of shut in. Two retention mechanisms were modelled: hydrodynamic and solubility trapping. Solubility trapping was found to be the most important means for storing CO2. This effect was enhanced by the creation of convective flow patterns which lead to a greater dissolution Of CO2. Tests were carried out on a homogeneous model, and the effects of CO2 diffusion in brine, vertical to horizontal permeability ratio, residual saturations, salinity and injection well completion interval were investigated. Results were compared with those from other studies to develop a more general understanding of factors affecting CO2 storage. To increase the realism of this study, the effect of geological heterogeneity was also examined. Three types of heterogeneity were investigated: low level random variations in sandstone permeability, stochastic shale layers and a fault. The low level heterogeneity did not have a large effect, although it distorted the convective pattern, while the presence of shales did have a large effect. CO2 tends to become trapped beneath the shale layers increasing the lateral migration. The amount of dissolved CO2 was largest in the models with an intermediate amount of shale. It was found that the fault did not affect the pressure distribution in the aquifer, unless the transmissibility was very low. However, the distribution of CO2 was affected by the location of the well relative to the fault. © 2006 Institution of Chemical Engineers.

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