International Journal of Greenhouse Gas Control 5 (2011) 75–87 Contents lists available at ScienceDirect International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc Supercritical CO 2 core flooding and imbibition in Tako sandstone—Influence of sub-core scale heterogeneity Ji-Quan Shi a,∗ , Ziqiu Xue b,c , Sevket Durucan a a Department of Earth Science and Engineering, Royal School of Mines, Imperial College London, Exhibition Road, London SW7 2AZ, UK b Department of Civil and Earth Resources Engineering, Kyoto University, Nishikyo-ku, Kyoto 615-8540, Japan c Research Institute of Innovative Technology for the Earth, Kizugawa City, Kyoto 619-0292, Japan article info Article history: Received 22 February 2010 Received in revised form 8 June 2010 Accepted 12 July 2010 Available online 5 August 2010 Keywords: Supercritical CO2 core flooding Imbibitions X-ray CT imaging Residual CO2 saturation Numerical simulation abstract This paper presents a numerical simulation study of a full CO 2 core flooding and imbibition cycle per- formed on a heterogeneous Tako sandstone core (measured 14.5 cm long and 3.68 cm in diameter). During the test, supercritical CO 2 (at 10 MPa and 40 ◦ C) and CO 2 -saturated brine was injected into one end of the horizontal core and a X-ray CT scanner (with a resolution of 0.35 mm × 0.35 mm) was employed to monitor and record changes in the fluid saturations, which enabled 3D mapping of the saturation pro- files throughout the core during the course of core flooding test. The CO 2 flooding test demonstrated that (1) sub-core porosity heterogeneity had a marked impact on the CO 2 migration pattern within the Tako sandstone core at low injection rates (∼0.1 cm 3 /min); (2) the influence of the porosity heterogeneity on the mean CO 2 saturation profiles along the core became gradually diminished as the injection rate was increased in steps to 3 cm 3 /min. The numerical simulation results have shown that the immiscible displacement processes in the het- erogeneous Tako core could not be adequately described by using a single capillary pressure curve in a 1D model of the core. This was found to be the case even when a 3D model (5 × 5 × 24) was used, where the porosity/permeability heterogeneity across the cross-sections, as well as along the core, was taken into account. Furthermore, the apparent correlation between the CO 2 saturation and the porosity (mean) profiles during the CO 2 flooding could largely be accounted for by employing a Leverett J-function type scaling factor, which reflects the influence of porosity/permeability heterogeneity on the capillary pressure. © 2010 Elsevier Ltd. All rights reserved. 1. Introduction Carbon capture and storage has been increasingly viewed as a promising technology to mitigate climate changes caused by global warming in short-to-medium terms, and as a potential means to bridge the transition from a fossil fuel-dominated to a low car- bon energy world. Among the different main types of potential storage formations, namely saline aquifers, depleted hydrocarbon reservoirs and unminable coal seams, saline aquifers have by far the largest estimated CO 2 storage capacity world-wide. Three stor- age mechanisms in aquifers have been identified, in increasing order of time scale, hydrodynamic (or residual CO 2 saturation) trap- ping, solution trapping (dissolution in the formation water), and mineral trapping through geochemical reactions with formation fluids and rocks (e.g. Mito et al., 2008). A proper understanding of these mechanisms for a given storage site is important in order ∗ Corresponding author. Tel.: +44 020 7594 7374; fax: +44 020 7594 7354. E-mail address: j.q.shi@imperial.ac.uk (J.-Q. Shi). to improve public confidence in the long-term subsurface storage of CO 2 . As CO 2 is injected into a storage formation, it tends to more upwards under its own buoyancy, as well as spread laterally driven by the pressure differential. The lateral spread of a CO 2 plume away from its source over a given time period would be to a large extent controlled by the residual saturation trapping mechanism, through which, part of the free phase CO 2 becomes immobile. The residual gas saturation for a reservoir rock is usually measured in labora- tory using core analysis techniques. Mulyadi et al. (2000) compared various core analysis techniques used for measuring residual gas saturation in water-driven gas reservoir. Recently computerised tomography (CT) has been increasingly used to visualise changes in situ saturation distribution during a core flooding experiment for both enhanced oil recovery (Yu et al., 1998; Oshita et al., 2000) and CO 2 storage (Izgec et al., 2006; Perrin et al., 2009). Yu et al. (1998) conducted complete gas- and oil-injection cycles at the reservoir conditions of 20 MPa pressure and 100 ◦ C temperature under X-ray CT monitoring to obtain oil and gas in situ saturation condition at irreducible water saturation. Izgec et 1750-5836/$ – see front matter © 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2010.07.003