Research paperStable carbon isotope techniques to quantify CO2 trapping under pre-equilibrium conditions and elevated pressures and temperatures
Highlights
► Flow-through experiments verify δ13C observations made in CO2 injection-projects. ► Geochemical trapping could be quantified in the laboratory under pre-equilibrium and high P–T conditions. ► The amount of CO2 remaining in free phase vs. trapped could be quantified. ► The state and trends of carbonate equilibrium under high P–T conditions could be determined.
Introduction
Interactions between CO2, rock and water especially occur in hydrogeological systems containing large amounts of CO2. These are typically natural gas fields, aquifers containing mineral waters or volcanic systems. These environments can also serve as natural analogues to CO2 injection projects, such as carbon capture storage (CCS) or enhanced oil/gas recovery (EOR/EGR) (Assayag et al., 2009, Gilfillan et al., 2009, Quattrocchi et al., 2009, Keating et al., 2011). This manuscript focuses on CO2 injection experiments as examples for systems where CO2–water–rock interactions are expected, such as found during CCS.
Ultimately, the goal of CCS is to trap CO2 securely in the subsurface. Various CO2 trapping mechanisms exist and may be categorised as either physical or geochemical trapping. Physical trapping is the capturing of CO2 by structural or stratigraphic formations (Hesse et al., 2009) or by capillary forces (Pentland et al., 2011). The amount of CO2 that can be trapped geochemically depends on the ability of CO2 to dissolve (Spycher and Pruess, 2005, Duan and Li, 2008). Geochemical trapping can be further divided into solubility-, ionic- and mineral trapping. Solubility trapping occurs when injected CO2 dissolves in fluids to form carbonic acid (H2CO3), ionic trapping, when HCO3− and CO32 − are formed and mineral trapping, when CO2 is trapped as stable carbonate minerals (Bachu, 2002, IPCC, 2005). The distribution of DIC species is pH dependant (Clark and Fritz, 1997) and defines therefore the form of trapping. Solubility trapping is dominant up to a pH of 6.4, ionic trapping between pH 6.4 and 10.3 and mineral trapping beyond pH 10.3. Solubility and ionic trapping are expected to be the dominant form of storage within 10s to 1000s of years, whereas mineral trapping is expected to show only significant effects beyond these time periods (IPCC, 2005, Gilfillan et al., 2009). As mineral trapping was not expected in this study, the term ‘geochemical trapping’ refers here only to CO2 trapped as dissolved inorganic carbon (DIC), i.e. as solubility and ionic trapping.
Especially in the initial stages of CO2 injection, a comprehensive understanding of the potential geochemical reactions between the supercritical (above 73.8 bar and 31.1 °C) CO2 and the host rock and fluids is fundamental. The highest pre-equilibrium conditions in the carbonate-system are expected in near injection well regions, which may have serious consequences for guaranteeing reservoir performance during CO2 injection operations (Luquot and Gouze, 2009). The formation of carbonic acid, for instance, causes calcite dissolution and hence increases porosity. However, depending on the geochemical conditions, minerals, including carbonates, may also precipitate elsewhere and cause a decrease in porosity and permeability further away from the injection well (Rosenbauer et al., 2005, Luquot and Gouze, 2009). Furthermore, a lowered pH caused by CO2 injection could pose an environmental hazard if pathways are created in rock seals or well cements through mineral dissolution. This would enable CO2 leakage and consequently, the acidified water could potentially mobilise metals in the groundwater (Kharaka et al., 2009, Kharaka et al., 2010). All of these situations require monitoring of the injected CO2 and a close assessment of the state and development of carbonate equilibrium in the host reservoir.
Common geochemical parameters used for CO2 injection monitoring include pH and calcium (Ca2 +) concentrations. With increasing CO2 dissolution, pH is expected to drop, hence, it has been suggested by Kharaka et al. (2006) as a sensitive parameter to track the arrival of CO2. Ca2 + concentrations are expected to increase during CO2 injection but have been proven to be less sensitive than δ13C for monitoring purposes (Emberley et al., 2005). So far, stable carbon isotopes (δ13C), as intrinsic tracers, have shown promising results to monitor the fate of CO2 in CO2-injection projects (Emberley et al., 2004, Kharaka et al., 2006, Raistrick et al., 2006, Gilfillan et al., 2009, Johnson et al., 2009, Myrttinen et al., 2010, Johnson et al., 2011b, Pauline et al., 2011).
Quantifying the amount of geochemical trapping, i.e. determining the fraction of DIC originating from injected CO2, may be of great challenge, if at all possible, if determined solely by mass balance calculations based on DIC concentrations. This holds true especially if numerous or unknown DIC sources exist. Isotope balance calculations with δ13C, on the other hand, as observed at CO2 injection sites, such as at Ketzin (Germany) or Weyburn (Canada), have proven to be a valuable method to quantify geochemical trapping (Raistrick et al., 2006, Myrttinen et al., 2010). In order to test the accuracy of the isotope balance method to quantify the amount of DIC originating from various sources, the isotope balance method was compared to mass balance calculations based on DIC concentration analyses of known sources.
Such quantification of geochemical trapping, however, does not allow differentiation between dissolved- and free phase-CO2. Quantifying the amount of total trapped CO2 is crucial in order to develop a CO2 budget for a CCS project, as well as to determine the amount of CO2 remaining in free-phase in the host aquifer (Johnson et al., 2011a). Particularly quantification of the latter is important as it could migrate away from the reservoir and reach the surface (Lewicki et al., 2007, Lemieux, 2011). Quantitative assessment of CO2 trapping, though, has proven to be challenging for various reasons, including geophysical limitations in detecting dissolved CO2 or maintaining in situ geochemical conditions during sampling (Johnson et al., 2011a). On the other hand, new promising methods have been described using oxygen isotopes of water (Johnson et al., 2011a), whereas other examples include geoelectrical methods (Kiessling et al., 2010).
In this study, stable carbon isotopes, together with DIC and Ca2 + concentrations and pH, were analysed to investigate CO2–water–rock interactions under dynamic and supercritical CO2 conditions, typically found in geological formations during CO2 injection. For this, several flow-through experiments were conducted in the laboratory by injecting CO2 saturated brines through a limestone rock sample. The objectives of this study were to investigate the following points, which so far have not been investigated by laboratory investigations, as described here:
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quantify geochemical trapping
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quantify the percentage of total CO2 dissolved in the fluid versus the amounts remaining in free phase
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determine the state of equilibrium of the carbonate system under laboratory conditions.
Results gained during these experiments are useful for comparison with field conditions and may provide insights into natural deep groundwater systems, especially in pre-equilibrium conditions, where such extreme CO2–water–rock interactions with brines may have a much greater influence on injection operations than previously thought.
Section snippets
Rock samples
Three experiments (E1, E2 and E3) were conducted using cylindrical rock plugs consisting of quartzitic limestone from the Aquitain basin (SW France), containing 70% calcite, 27% quartz, 2% clay minerals and 1% goethite. Due to the high calcite content, pronounced carbonate dissolution was expected, which is one of the key reactions in near injection well regions in the reservoir, during initial stages of CO2 injection. The rock plugs had different volumes: 25.3 cm3 (E1), 16.2 cm3 (E2) and 8.3 cm3
Results
The following δ13CDIC, DIC, Ca2 + and pH monitoring results (Fig. 2) are subdivided into three sections: a) baseline, b) pre-CO2 breakthrough and c) post-CO2 breakthrough (cf. supplementary material). Table 1 describes the injection data and CO2 breakthrough times, which is defined here as the point when CO2 appeared in gaseous form the first time at noticeable amounts at the outlet sampling port.
Baseline values
The difference (18.4‰) between the δ13C endmember values of injected carbon and baseline DIC in these experiments were comparable to ones reported in field investigations (Table 2). At the Ketzin (Germany), Weyburn (Canada) or Frio Formation (USA) sites, for instance, these differences ranged between 12.9 and 41‰ (Emberley et al., 2004, Kharaka et al., 2006, Raistrick et al., 2006, Myrttinen et al., 2010). Furthermore, isotope balance calculations have been successfully conducted both at Ketzin
Conclusion
A set of three flow-through experiments was conducted in the laboratory to simulate CO2 injection, at supercritical conditions, through a limestone rock plug. Pre-equilibrium conditions in the carbonate system were maintained, as are expected in initial stages of CO2 injection, especially in near injection well regions of the reservoir. CO2–water–rock reactions were monitored with stable carbon isotopes in combination with DIC and Ca2 + concentration data. δ13CDIC proved to be a suitable tracer
Acknowledgements
We would like to thank Électricité de France (EDF), who funded aspects of the research and the Karlsruhe Institute for Technology (KIT), for giving us access to the ICARE4 test bench and providing us with the microscope image. Our gratitude also goes to the “Regierungspräsidium Freiburg, Baden-Württemberg, Landesamt für Geologie, Rohstoffe und Bergbau” for conducting the mineralogical analysis of the rock plug. The isotope and DIC measurements were funded by the German Ministry of Education and
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