Mineral sequestration of carbon dioxide in basalt: A pre-injection overview of the CarbFix project

In this paper we describe the thermodynamic and kinetic basis for mineral storage of carbon dioxide in basaltic rock, and how this storage can be optimized. Mineral storage is facilitated by the dissolution of CO₂ into the aqueous phase. The amount of water required for this dissolution decreases with decreased temperature, decreased salinity, and increased pressure. Experimental and field evidence suggest that the factor limiting the rate of mineral fixation of carbon in silicate rocks is the release rate of divalent cations from silicate minerals and glasses. Ultramafic rocks and basalts, in glassy state, are the most promising rock types for the mineral sequestration of CO₂ because of their relatively fast dissolution rate, high concentration of divalent cations, and abundance at the Earth's surface. Admixture of flue gases, such as SO₂ and HF, will enhance the dissolution rates of silicate minerals and glasses. Elevated temperature increases dissolution rates but porosity of reactive rock formations decreases rapidly with increasing temperature. Reduced conditions enhance mineral carbonation as reduced iron can precipitate in carbonate minerals. Elevated CO₂ partial pressure increases the relative amount of carbonate minerals over other secondary minerals formed. The feasibility to fix CO₂ by carbonation in basaltic rocks will be tested in the CarbFix project by: (1) injection of CO₂ charged waters into basaltic rocks in SW Iceland, (2) laboratory experiments, (3) studies of natural analogues, and (4) geochemical modelling.     

Carbonate mineralization of volcanic province basalts

Flood basalts are receiving increasing attention as possible host formations for geologic sequestration of anthropogenic CO₂, with studies underway in the United States, India, Iceland, and Canada. Basalts from the United States, India, and South Africa were reacted with aqueous dissolved CO₂ and aqueous dissolved CO₂–H₂S mixtures under supercritical CO₂ (scCO₂) conditions to study the geochemical reactions resulting from injection of CO₂ in such formations. Despite the basalt samples having similar bulk chemical composition, mineralogy and dissolution kinetics, long-term static experiments show significant differences in rates of mineralization as well as compositions and morphologies of precipitates that form when the basalts are reacted with CO₂ and CO₂–H₂S mixtures in water. For example, basalt from the Newark Basin in the United States was by far the most reactive of any basalt tested to date. Reacted grains from the Newark Basin basalt appeared severely weathered and contained extensive carbonate precipitates with significant Fe content. In comparison, the post-reacted samples associated with the Columbia River basalts from the United States contained calcite grains with classic “dogtooth spar” morphology and trace cation substitution (Mg and Mn). Carbonation of the other basalts produced precipitates with compositions that varied chemically throughout the entire testing period. The Karoo basalt from South Africa appeared the least reactive, with very limited mineralization occurring during the testing with CO₂-saturated water. Compositional differences in the precipitates suggest changes in fluid chemistry unique to the dissolution behavior of each basalt sample reacted with CO₂-saturated water. No convincing correlations were identified between basalt reactivity and differences in bulk composition, mineralogy, glassy mesostasis quantity or composition. Moreover, the relative reactivity of different basalt samples was unexpectedly different in the experiments conducted with aqueous dissolved CO₂–H₂S mixtures versus those with CO₂ only. For example, the Karoo basalt was highly reactive in the presence of aqueous dissolved CO₂–H₂S, as evident by nodules of carbonate coating the basalt grains after 181 days of testing. However, the most reactive basalt in CO₂–H₂O, Newark Basin, formed only iron sulfide coatings in tests with a CO₂–H₂S mixture, which inhibited carbonate mineralization.     

A natural analogue for CO2 mineral sequestration in Miocene basalt in the Kuanhsi-Chutung area, Northwestern Taiwan

In general, CO₂ sequestration by carbonation is estimated by laboratory experimentation and geochemical simulation. In this study, however, estimation is based on a natural analogue study of the Miocene basalt in the Kuanhsi-Chutung area, Northwestern Taiwan. This region has great potential in terms of geological and geochemical environments for CO₂ sequestration. Outcropping Miocene basalt in the study area shows extensive serpentinization and carbonation. The carbon stable isotopes of carbonates lie on the depleted side of the Lohmann meteoric calcite line, which demonstrates that the carbonates most probably precipitate directly from meteoric fluid, and water–rock interaction is less involved in the carbonation process. Oxygen stable isotope examinations also show much depleted ratios, representative of product formation under low temperatures (∼50–90 °C). This translates to a depth of 1–2 km, which is a practical depth for a CO₂ sequestration reservoir. According to petrographic observation and electron microprobe analysis, the diopside grains in the basalt are resistant to serpentinization and carbonation; therefore, the fluid causing alteration is likely enriched with calcium and there must be additional sources of calcium for carbon mineralization. These derived geochemical properties of the fluid support the late Miocene sandstone and enclosed basalts as having high potential for being a CO₂ sequestration reservoir. Moreover, the existing geochemical environments allow for mineralogical assemblages of ultramafic xenoliths, indicating that forsterite, orthopyroxene and feldspar minerals are readily replaced by carbonates. Based on the mineral transformation in xenoliths, the capacity of CO₂ mineral sequestration of the Miocene basalt is semi-quantitatively estimated at 94.15 kg CO₂ chemically trapped per 1 m³ basalt. With this value, total CO₂ sequestration capacity can be evaluated by a geophysical survey of the amount of viable Miocene basalt at the potential sites. Such a survey is required in the near future.     

Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

Measurements of non-wetting phase trapping applied to carbon dioxide storage

We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for CO₂ storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO₂ immobile. The CO₂ is injected into the formation followed by chase brine injection, or natural groundwater flow, which displaces and traps CO₂ on the pore scale as a residual immobile phase. Current models to predict the amount of trapping are based on experiments in consolidated media, while CO₂ may be stored in relatively shallow, poorly consolidated systems. We use analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation. This behaviour is not predicted by the traditional literature trapping models, but is physically consistent with unconsolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. A good match to our experimental data was achieved with the trapping model proposed by Aissaoui.     

Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

Industrial-scale injection of CO₂ into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO₂ storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO₂ storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO₂ per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO₂–brine flow processes and the large-scale groundwater flow patterns in response to CO₂ storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO₂ storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO₂, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO₂ sequestration projects.     

Storage of CO2 in natural gas hydrate reservoirs and the effect of hydrate as an extra sealing in cold aquifers

Reservoirs of clathrate hydrates of natural gases (hydrates), found worldwide and containing huge amounts of bound natural gases (mostly methane), represent potentially vast and yet untapped energy resources. Since CO₂-containing hydrates are considerably more stable thermodynamically than methane hydrates, if we find a way to replace the original hydrate-bound hydrocarbons by the CO₂, two goals can be accomplished at the same time: safe storage of carbon dioxide in hydrate reservoirs, and in situ release of hydrocarbon gas. We have applied the techniques of Magnetic Resonance Imaging (MRI) as a tool to visualize the conversion of CH₄ hydrate within Bentheim sandstone matrix into the CO₂ hydrate. Corresponding model systems have been simulated using the Phase Field Theory approach. Our theoretical studies indicate that the kinetic behaviour of the systems closely resembles that of CO₂ transport through an aqueous solution. We have interpreted this to mean that the hydrate and the matrix mineral surfaces are separated by liquid-containing channels. These channels will serve as escape routes for released natural gas, as well as distribution channels for injected CO₂.     

Numerical simulations on the influence of matrix diffusion to carbon sequestration in double porosity fissured aquifers

The double porosity model for fissured rocks, such as limestones and dolomites, has some features that may be relevant for carbon sequestration. Numerical simulations were conducted to study the influence of matrix diffusion on the trapping mechanisms relevant for the long-term fate of CO₂ injected in fissured rocks. The simulations show that, due to molecular diffusion of CO₂ into the rock matrix, dissolution trapping and hydrodynamic trapping are more effective in double porosity aquifers than in an equivalent porous media. Mineral trapping, although assessed indirectly, is also probably more relevant in double porosity aquifers due to the larger contact surface and longer contact time between dissolved CO₂ and rock minerals. However, stratigraphic/structural trapping is less efficient in double porosity media, because at short times CO₂ is stored only in the fissures, requiring large aquifer volumes and increasing the risk associated to the occurrence of imperfections in the cap-rock through which leakage can occur. This increased risk is also a reality when considering storage in aquifers with a regional flow gradient, since the CO₂ free-phase will move faster due to the higher flow velocities in fissured media and discharge zones may be reached sooner.     

Storage of CO2 in saline aquifers: Effects of gravity, viscous, and capillary forces on amount and timing of trapping

CO₂ can be effectively immobilized during CO₂ injection into saline aquifers by residual trapping – also known as capillary trapping – a process resulting from capillary snap-off of isolated CO₂ bubbles. Simulations of CO₂ injection were performed to investigate the interplay of viscous and gravity forces and capillary trapping of CO₂. Results of those simulations show that gas injection processes in which gravitational forces are weak compared to viscous forces (low gravity number N_gv) trap significantly more CO₂ than do flows with strong gravitational forces relative to the viscous forces (high N_gv). The results also indicate that over a wide range of gravity numbers (N_gv), significant fractions of the trapping of CO₂ can occur relatively quickly. The amount of CO₂ that is trapped after injection ceases is demonstrated to correlate with N_gv. For some simulated displacements, effects of capillary pressure and aquifer dip angle on the amount and the rate of trapping are reported. Trapping increases when effects of capillary pressure and aquifer inclination are included in the model. Finally we show that injection schemes such as alternating injection of brine and CO₂ or brine injection after CO₂ injection can also enhance the trapping behavior.     

Evaluating geological sequestration of CO2 in bituminous coals: The southern Sydney Basin,Australia as a natural analogue

Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO₂ that was introduced from deep magmatic sources via faults and replaced pre-existing CH₄. In some respects this process is analogous to sequestration of anthropogenic CO₂. Laboratory studies indicate that CO₂:CH₄ storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO₂ by a factor of up to 1.5.Present-day distribution of CO₂ in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P–T conditions, most of the CO₂ occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO₂ occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO₂ solubility. The CO₂ has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO₂ sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P–T conditions.In situ CO₂ contents of Sydney Basin coals range up to 20 m³/t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO₂ stored do not exceed ∼60% of the total CO₂ storage capacity. Therefore, the maximum CO₂ saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.     

Lessons learned from natural and industrial analogues for storage of carbon dioxide

The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO₂. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues.At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods.In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO₂ toward surface. This study also provides information on the origin of CO₂, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story.The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO₂. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state.These two complementary studies proved the interest of geochemical monitoring to survey the CO₂ behaviour, and gave information on its use.     

Preliminary assessment of CO2 geological storage opportunities in Greece

This paper provides a preliminary assessment of the suitability of Tertiary sedimentary basins in Northern, Western and Eastern Greece in order to identify geological structures close to major CO₂ emission sources with the potential for long-term storage of CO₂. The term “emissions” refers to point source emissions as defined by the International Energy Agency, including power generation, the cement sector and other industrial processes. The Prinos oil field and saline aquifer, along with the saline formations of the Thessaloniki Basin and the Mesohellenic Trough have been identified as prospective CO₂ geological storage sites. In addition, a carbonate deep saline aquifer occurring at appropriate depths beneath the Neogene-Quaternary sediments of Ptolemais-Kozani graben (NW Greece) is considered. The proximity of this geological formation to Greece's largest lignite-fired power plants suggests that it would be worthwhile undertaking further site-specific studies to quantify its storage capacity and assess its structural integrity.     

CO2 storage capacity estimation: Methodology and gaps

Implementation of CO₂ capture and geological storage (CCGS) technology at the scale needed to achieve a significant and meaningful reduction in CO₂ emissions requires knowledge of the available CO₂ storage capacity. CO₂ storage capacity assessments may be conducted at various scales—in decreasing order of size and increasing order of resolution: country, basin, regional, local and site-specific. Estimation of the CO₂ storage capacity in depleted oil and gas reservoirs is straightforward and is based on recoverable reserves, reservoir properties and in situ CO₂ characteristics. In the case of CO₂-EOR, the CO₂ storage capacity can be roughly evaluated on the basis of worldwide field experience or more accurately through numerical simulations. Determination of the theoretical CO₂ storage capacity in coal beds is based on coal thickness and CO₂ adsorption isotherms, and recovery and completion factors. Evaluation of the CO₂ storage capacity in deep saline aquifers is very complex because four trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operating simultaneously. The level of detail and resolution required in the data make reliable and accurate estimation of CO₂ storage capacity in deep saline aquifers practical only at the local and site-specific scales. This paper follows a previous one on issues and development of standards for CO₂ storage capacity estimation, and provides a clear set of definitions and methodologies for the assessment of CO₂ storage capacity in geological media. Notwithstanding the defined methodologies suggested for estimating CO₂ storage capacity, major challenges lie ahead because of lack of data, particularly for coal beds and deep saline aquifers, lack of knowledge about the coefficients that reduce storage capacity from theoretical to effective and to practical, and lack of knowledge about the interplay between various trapping mechanisms at work in deep saline aquifers.     

Integration of counter-current relative permeability in the simulation of CO2 injection into saline aquifers

Carbon dioxide (CO₂) injection into saline aquifers is one of the promising options to sequester large amounts of CO₂ in geological formations. During as well as after injection of CO₂ into an aquifer, CO₂ migrates towards the top of the formation due to density differences between the formation brine and the injected CO₂. The time scales of CO₂ migration towards the top of an aquifer and the fraction of CO₂ that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO₂.When CO₂ migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO₂ storage into saline aquifers.In this paper we study the impact of changes in mobility for the two-phase brine/CO₂ system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO₂ in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO₂ in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO₂ storage in saline aquifers.     

Regulatory challenges and managing public perception in planning a geological storage pilot project in Australia

The implementation of geological storage of CO₂ requires not only further research and development but also the demonstration of carbon dioxide capture and storage (CCS) technology as a viable option. A pilot program is an important first step towards building industry and community confidence in the application of CCS. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia's leading research organisation in CCS, has initiated a comprehensive research and demonstration program in the Otway Basin in South-West Victoria. As the first project of its kind in Australia, the Otway Basin Pilot Project (OBPP) has faced a number of regulatory and organisational challenges while having to concurrently address public perception. The Otway Basin site with its natural CO₂ accumulations and many depleted natural gas fields offers an appropriate CO₂ storage site to test scientific and regulatory concepts and evaluate public response through social research. The project aims to show that CO₂ can be safely captured, transported and stored deep underground under local conditions, and also monitored and verified. Planning has been ongoing for over a year, baseline studies are underway and the project is targeted to start injection in 2007.     

Dynamis CO2 quality recommendations

In the carbon capture and storage (CCS) chain, transport and storage set different requirements for the composition of the gas stream mainly containing carbon dioxide (CO₂). Currently, there is a lack of standards to define the required quality for CO₂ pipelines. This study investigates and recommends likely maximum allowable concentrations of impurities in the CO₂ for safe transportation in pipelines. The focus is on CO₂ streams from pre-combustion processes. Among the issues addressed are safety and toxicity limits, compression work, hydrate formation, corrosion and free water formation, including the cross-effect of H₂S and H₂O and of H₂O and CH₄.     

Simultaneous CO2 injection and water production to optimise aquifer storage capacity

The estimates for geological CO₂ storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO₂ that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential.In static capacity estimates, where the maximum stored amount of CO₂ is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO₂ is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO₂. The EU directive on geological CO₂ storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO₂ that can be injected.One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO₂ injection wells. This paper discusses results from simulations of CO₂ injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO₂ shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO₂ over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer.Several design options for the injection operations are investigated: Injection of CO₂ without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.