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Abstract
The aim of this paper is to investigate the effects of CO2 sequestration on groundwater abstraction above the storage formation. Large-scale (10Mt/yr) CO2 injection in underlying saline aquifers is considered using a fully compositional simulator to study the pressure distribution, CO2 leakage and inter-layer brine flow. Structural, residual and solubility CO2 trapping are taken into account while the model domain is considered to have no-flow boundaries to simulate CO2 injection under the context of either pressure not being able to be dissipate quickly (due to other CO2 injection processes, for instance) or the formation being self-contained. Changes in salinity are affected by groundwater abstraction and although not caused by injection itself, can be magnified by such processes. We also conclude that the time at which CO2 leakage, pressure perturbations and upward brine flow are at their peak in overlying aquifers (layers above the injection site) may be signifi-cantly after injection has ceased (50-150 years in some cases) and could potentially cause groundwater movements, land sur-face uplift or rock fracturing long after the injection phase has ended.

Introduction
Current levels of CO2 are around 390ppm (parts per million) (NOAA, 2009) and a further increase beyond 400-450ppm is likely to cause further climate changes (Meinshausen, 2006). It has been suggested that carbon capture and storage (CCS) can help to mitigate this adverse climatic impact (IPCC, 2005, Houghton, 2001, Jepma & Munasinghe, 1998, Bryant, 1997, Holloway, 1996). CO2 can be separated and captured from stationary sources such as coal-fired power stations, transported to a suitable location and subsequently stored underground as opposed to being emitted into the air.

Different geological storage locations have been considered in literature such as basalt rocks (McGrail et al., 2006), salt caverns (Dusseault et al., 2001) and former coal mines (Shi & Durucan, 2005, Wo & Liang, 2005). The main focus of past and current research, however, has been on oil and gas fields – either depleted or in the context of enhanced oil recovery (EOR) – and deep saline formations or aquifers (Holloway et al., 2005) which this paper will focus on.
A saline aquifer is a geological formation that contains water with dissolved salts. Because of the high salinity in these formations they are not usually used as a source of drinking water (U.S. Environmental Protection Agency, 2009) and hence are considered to be a suitable target for CO2 storage, provided it can be stored safely over long periods of time. When CO2 is injected into a geological formation several trapping mechanisms occur at varying timescales, namely structural and stratigraphic trapping (Lindeberg, 1997), residual or capillary trapping (van der Meer, 1995, Holt et al., 1995, Law & Bachu, 1996, Spiteri et al., 2008), solubility trapping (Law & Bachu, 1996, Spycher et al., 2003, Spycher & Pruess, 2005) and mineral trapping (Pruess et al., 2003, Gunter et al., 2004, Xu et al., 2004, Kumar et al., 2005). Another, more recent approach, suggested storing CO2 directly as a solid through hydrate formation (Wright et al., 2008), a process requiring significantly more research and therefore outside the scope of this paper.

Numerical modeling of CO2 storage has been performed since the early 1990’s (Holloway, 1996, van der Meer, 1995, Holt et al., 1995, Law & Bachu, 1996, van der Meer, 1992, van der Meer, 1993, van der Meer, 1996) and, although computationally expensive, can capture phenomena not considered in analytical solutions. More recently, researchers have studied near basin-scale systems and long time frames, applicable to large storage sites (Kumar et al., 2005, Mo & Akervoll, 2005, Ozah et al., 2005, Akaku, 2008). Research on the basis of these numerical models has been extended to study the large-scale impact CO2 injection has on groundwater systems and up-dip or overlying fresh water aquifers, suggesting that especially the pressure distribution and displacement of brine could have an impact on a much larger scale than the CO2 plume itself (Nicot, 2008, Birkholzer et al., 2009, Birkholzer & Zhou, 2009).