Abstract

Carbon geosequestration in deep saline aquifers is an efficient way to mitigate climate change due to greenhouse gas emissions. The carbonate reservoir is the one of the selected storage site, however, such carbonate rock is sensitive to the acidic environment - where the CO2 saturated formation water could be as medium acid in the reservoir condition. Thus, fully understand such CO2-water-rock interaction and the related rock mechanical properties change are very important for the storage security. However, how the elastic moduli change in the different storage areas are still blank. In this paper, we thus injected scCO2 and CO2 saturated (live) brine into Savonnières limestone core plugs at reservoir conditions to simulate the different areas in the real geosequestration sites. The flooding tests were set as a representative reservoir conditions at approximately 1000m depth with 325 K, 15 MPa confining pressure and 10 MPa pore pressure. The X-ray CT scanning and ultrasonic tests were conducted to monitor the change before and after the flooding. The morphology results showed that the CO2 saturated brine injection had larger dissolution effect than scCO2 and consistent with the calculated Young's moduli change. Moreover, the Poisson's ratio slightly had slightly dropped after scCO2 flooding but build up by live brine. We thus suggested that Poisson's ratio could be used to monitor the CO2 underground conditions (supercritical condition or saturated with brine) in such limestone carbon storage which need more future investigations.

Introduction

CO2 storage in the deep geological formation is the best choice for zero carbon emission during human activities (Al-Yaseri et al., 2017b; Al-Khdheeawi et al., 2018; Birkholzer et al., 2009; Zhang et al., 2016b). The CO2 deep trapping mechanisms including structure trapping (Bentham and Kirby, 2005; Benson and Cole, 2008), solubility trapping (Meng and Jiang, 2014; Gasda et al., 2011; Lebedev et al., 2017b), residual trapping (Al-Khdheeawi et al., 2017; Al-Yaseri et al., 2017c; Lebedev et al., 2017a), adsorption trapping ((Jin et al., 2017b; Kim et al., 2017; Zhang et al., 2016d, 2017) and mineral trapping (Jin et al., 2017a; Yasuhara et al., 2017; Pearce et al., 2018). The solubility trapping is the basic and secure trapping mechanisms where the injected CO2 dissolved into the formation water, has been thought as the first stage trapping method in the conventional reservoirs (Lebedev et al., 2017b). Technically, the CO2 saturated brine has higher density when comparing to the surrounding original formation water and thus seeks deep into the target formation (but not go up) - thus be very securely (Lindeberg and Wessel-Berg, 1997). Moreover, such CO2 saturated brine is a medium acid fluid in the reservoir conditions and the in-situ pH value can be researched as low as 3 – 4 (Deng et al., 2015). However, the carbonate rock (e.g. limestone reservoir - mainly calcite) as the typical hosted reservoir is sensitive to the acid environment and the impacts on permeability and formation matrix integrity can be significantly (Lebedev et al., 2017b; Luquot and Gouze, 2009). Thus, such rock matrix dissolved can largely affect the mechanical stable of the reservoir formation which needs to be seriously investigated to ensure the geosequestration site secure and efficient (Lebedev et al., 2017b; Zhang et al., 2016a, 2016c).

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