Underground CO2 Research Articles

FEP Analysis and Markov Chains

Uncertainties related with underground CO2 storage play a vital role in risk assessment with respect to Carbon storage and capture projects (CCS). The main purpose of risk assessment is to determine a qualitative and quantitative picture of hazardous processes or events. One makes a comprehensive inventory of risk factors, and stores the results in a FEP (Features, Events and Process) database. The properties of the geological system itself and natural or human -induced processes determine the future system p roperties. The FEP's may interact. In this paper we propose to describe this interaction of FEPs within the framework of (discrete time) Markov Chains. In such an approach various states are defined. The system can jump from one state to another. The probabilistic evolution of the system can be followed, and conclusions can be drawn as to visit times of the various states. Also, the most likely ultimate fate of a system in dependence of initial state can be determined. This approach offers a comple mentary supporting tool for scenario-thinking, as it takes into account the evolution of all possible follow -ups of relevant physical processes and events quantitatively. It is not about just following a few scenario's. Without the machinery of Markov Chains this can hardly be done in full. An added bonus of this approach is that questions of policy makers, and of licensing authorities can be answered in a numerical way. © 2009 Elsevier Ltd. All rights reserved.

“Wellbore Integrity...” Say What??

Convincing people to try something new, strange and expensive is not easy. Convincing them to embrace something that they fear and struggle to understand is almost impossible. Many people seem to fear CO2 Capture and Storage (CCS) and remain skeptical that it will evolve into a huge opportunity to control global CO2 emissions. It needs to be explained in terms normal people understand. Not everyone speaks the same language or starts from the same point of reference. This effort is by a high school junior using common language and images familiar to me and my friends to visualize basic science relationships related to the storage part of CCS: soccer balls and playing fields. It considers key components of well systems and makes comparisons with the behavior of natural phenomena like ant hills enduring in a light rain storm, and compares that with their fate when attacked by a little brother with a water hose. It asks questions about the dimensions of the systems, and how key components might work. It’s about putting CO2 underground, but how do you explain that with soccer balls? Instinctively, the big question is will the CO2 stay underground? What will happen to it with time? Why won’t it just come right back out a well like a straw? What about all those wells anyway? Should people get hyped-up about them? Aren’t they filled with cement? Think, CO2 in water makes an acid. What will that acid do? Is it about pumping and sucking fluids thru barriers as strong as steel instead of allowing them to flow freely in a hose? Stay tuned and read on. Full disclosure: This paper is not exactly cutting edge science; it offers no new data, and tests no hypothesis although it makes some original calculations. It’s about communication and visualization, so it deliberately dodges some important details about well construction techniques, reaction rates, kinetics and the multiphase behavior of supercritical CO2, even in the same reservoir. It touches on fundamentals of reservoir porosity and permeability, and even subsurface fluid flow but just barely. Just enough to be cool, stressed, over pressured and dense phased, more or less like the injected gas we care so much about.

Dissolution experiment of sedimentary rocks-Basic study for underground CO2 sequestration in aquifer.

Dissolution experiment of sedimentary rocks-Basic study for underground CO<SUB>2</SUB> sequestration in aquifer.

Underground gas storage: An introduction and UK perspective

Abstract Rising demand and the depletion of its offshore reserves has resulted in the UK becoming a net importer of natural gas. An increased reliance on imports and limited current storage availability mean that the UK faces increasing energy bills and risk of disruption to supply. Because of this the UK government has set about ensuring security of energy supply. Steps taken include the construction of major new pipelines from Norway and Holland and improvements to interconnectors in the southern North Sea. The Government also recognizes that improvements to the gas supply infrastructure are required, including the need for significant increases in gas storage capacity; best met by the construction of underground storage facilities. Focus on energy security has also raised the likelihood of a new generation of coal-fired power-stations. For such a step to be environmentally viable, clean-coal technologies with near-zero greenhouse gas emissions will be required. Underground CO 2 storage will be a key element of this strategy. This volume reviews the technologies and issues involved in the underground storage of natural gas and CO 2 , by means of case-studies and examples from the UK and also from overseas. The potential for underground storage of other gases such as hydrogen, or compressed air linked to renewable sources is also reviewed.

About this title - Underground Gas Storage: Worldwide Experiences and Future Development in the UK and Europe

The UK became a net importer of natural gas in 2004 and by 2020 will import up to 90% of its requirements, leaving it vulnerable to increasing energy bills and risk of disruption to supply. New pipelines to Europe and improvements to interconnectors will meet some demand, but Government recognizes the need for increased gas storage capacity: this may be best met by the construction of underground storage facilities. Energy security has also raised the likelihood of a new generation of coal-fired power-stations, which to be environmentally viable, will require clean-coal technologies with near-zero greenhouse gas emissions. A key element of this strategy will be underground CO 2 storage. This volume reviews the technologies and issues involved in the underground storage of natural gas and CO 2 , with examples from the UK and overseas. The potential for underground storage of other gases such as hydrogen, or compressed air linked to renewable sources is also reviewed.

CO2地中貯留への適用のための玄武岩質岩石の溶解実験

Dissolution rates of three basaltic rock samples from Japan (Fuji (sample1) and Hachijyojima (sample 2) fresh basaltic rocks, and Kitamatsuura (sample 3) altered basaltic rock) were experimentally determined in a pH range from 3 to 11 at 25°C. Initial dissolution rate constants are high (-9.9 ∼ -10.4 in logarithmic unit) . It is inferred that the initial dissolution rate is controlled by proton-cation (alkali, alkali earth and aluminium) ion exchange reaction and breakdown of Si-O bond in silicate. Long-term dissolution rate constants for Si determined are -11.5 ∼ -11.8 (in logarithmic unit) (sample1) and -11.3 ∼ -11.8 (sample 2) . These values are lower than those for artificial basalt glass previously obtained. The rate constant determined for sample 3 is consistent with those of feldspar previously studied. In future based on the present results on the dissolution rate of basaltic rocks, we will perform calculation on the temporal changes of the amount of carbonates precipitating from groundwater reacting with basaltic host rocks in order to estimate the amount of CO2 fixed by mineral trapping for underground CO2 sequestration in basaltic rock area in Japan.

Effect of organic and inorganic ligands on calcite and magnesite dissolution rates at 60 °C and 30 atm pCO 2

Calcite and magnesite dissolution rates were measured at 60 °C, 30 atm pCO 2, 0.1 M NaCl, and pH from 4.95 ± 0.05 to 5.60 ± 0.05 as a function of organic (acetate, oxalate, malonate, succinate, phthalate, citrate, EDTA) and inorganic (sulphate, phosphate, borate, silicate) ligand concentration in the range of 10 − 5 to 10 − 2 M. These conditions can be considered as boundary model environments for sedimentary oil-field basins of underground CO 2 storage. Experiments on dissolution of magnesite powders (100–200 µm) and calcite crystal planes were performed in a batch reactor with in-situ pH measurements and under controlled hydrodynamic conditions using the rotating disk technique. At 60 °C in circumneutral solutions in the presence of 0.02 M NaHCO 3 and 30 atm pCO 2 (pH = 4.95), calcite dissolution is weakly affected by the presence of ligands: the rates increase at the maximum by a factor of 2 and, at 0.01 M ligand concentration in solution, the order is: silicate < citrate < NaCl ∼ borate < malonate < EDTA < sulphate < acetate. The order of ligand effects on calcite dissolution at pH = 5.55 (0.1 M NaHCO 3, 30 atm pCO 2) is: phosphate < NaCl < citrate < acetate < succinate < malonate < phthalate < EDTA. Magnesite dissolution rates at 60 °C, 30 atm pCO 2 and 0.02 M NaHCO 3 (pH = 4.95) were weakly affected by the presence of acetate, silicate, borate and NaCl but increase in the presence of sulphate, EDTA, citrate and oxalate. These ligand-affected rates were rationalized using a phenomenological equation which postulates the Langmuirian adsorption of a negatively-charged or neutral ligand on rate-controlling surface sites, presumably > MeOH 2 + (Me = Ca, Mg). Proposed equations of rate–ligand concentration dependencies can be directly incorporated into reaction transport codes. Results obtained in this study demonstrate that both magnesite and calcite reactivity is not appreciably affected by acetate, oxalate, citrate, succinate, sulphate, and phosphate that are most likely present in deep carbonate aquifers at the physical and chemical conditions pertinent to CO 2 geological sequestering sites. The concentration of ligands necessary to increase the rates by a factor of 3 to 10 is on the order of 0.01 M. Such a high concentration is unlikely to be encountered in deep sedimentary basins. Therefore, as a first approximation, reactive transport modelling of dissolution induced by CO 2 injection in carbonate rocks does not require to explicitly account for the effect of dissolved organics.

Characterization of the CO2 fluid adsorption in coal as a function of pressure using neutron scattering techniques (SANS and USANS)

Abstract Small angle neutron scattering techniques have been applied to investigate the phase behavior of CO2 injected into coal and possible changes in the coal pore structure that may result from this injection. Three coals were selected for this study: the Seelyville coal from the Illinois Basin (Ro = 0.53%), Baralaba coal from the Bowen Basin (Ro = 0.67%), and Bulli 4 coal from the Sydney Basin (Ro = 1.42%). The coals were selected from different depths to represent the range of the underground CO2 conditions (from subcritical to supercritical) which may be realized in the deep subsurface environment. The experiments were conducted in a high pressure cell and CO2 was injected under a range of pressure conditions, including those corresponding to in-situ hydrostatic subsurface conditions for each coal. Our experiments indicate that the porous matrix of all coals remains essentially unchanged after exposure to CO2 at pressures up to 200 bar (1 bar = 105 Pa). Each coal responds differently to the CO2 exposure and this response appears to be different in pores of various sizes within the same coal. For the Seelyville coal at reservoir conditions (16 °C, 50 bar), CO2 condenses from a gas into liquid, which leads to increased average fluid density in the pores (ρpore) with sizes (r) 1 × 105 ≥ r ≥ 1 × 104 A (ρpore ≈ 0.489 g/cm3) as well as in small pores with size between 30 and 300 A (ρpore ≈ 0.671 g/cm3). These values are by a factor of three to four higher than the density of bulk CO2 (ρCO2) under similar thermodynamic conditions (ρCO2 ≈ 0.15 g/cm3). At the same time, in the intermediate size pores with r ≈ 1000 A the average fluid density is similar to the density of bulk fluid, which indicates that adsorption does not occur in these pores. At in situ conditions for the Baralaba coal (35 OC, 100 bar), the average fluid density of CO2 in all pores is lower than that of the bulk fluid (ρpore / ρCO2 ≈ 0.6). Neutron scattering from the Bulli 4 coal did not show any significant variation with pressure, a phenomenon which we assign to the extremely small amount of porosity of this coal in the pore size range between 35 and 100,000 A.

Cycle analysis of low and high H2 utilization SOFCs/gas turbine combined cycle for CO2 recovery

AbstractGlobal warming is mainly caused by CO2 emission from thermal power plants, which burn fossil fuel with air. One of the countermeasure technologies to prevent global warming is CO2 recovery from combustion flue gas and the sequestration of CO2 underground or in the ocean. SOFC and other fuel cells can produce high‐concentration CO2, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air, or diluted by N2. Thus, we propose to operate the multistage SOFCs under high utilization of reformed fuel for obtaining high‐concentration CO2. In this report, we have estimated the multistage SOFCs' performance considering H2 diffusion and the combined cycle efficiency of multistage SOFC/gas turbine/CO2 recovery power plant. The power generation efficiency of our CO2 recovery combined cycle is 68.5% and the efficiency of conventional SOFC/GT cycle is 57.8% including the CO2 recovery amine process. © 2009 Wiley Periodicals, Inc. Electron Comm Jpn, 91(10): 38–45, 2008; Published online in Wiley InterScience (www.interscience. wiley.com). DOI 10.1002/ecj.10165

Testing carbon sequestration site monitor instruments using a controlled carbon dioxide release facility

Two laser-based instruments for carbon sequestration site monitoring have been developed and tested at a controlled carbon dioxide (CO(2)) release facility. The first instrument uses a temperature tunable distributed feedback (DFB) diode laser capable of accessing the 2.0027-2.0042 microm spectral region that contains three CO(2) absorption lines and is used for aboveground atmospheric CO(2) concentration measurements. The second instrument also uses a temperature tunable DFB diode laser capable of accessing the 2.0032-2.0055 mum spectral region that contains five CO(2) absorption lines for underground CO(2) soil gas concentration measurements. The performance of these instruments for carbon sequestration site monitoring was studied using a newly developed controlled CO(2) release facility. A 0.3 ton CO(2)/day injection experiment was performed from 3-10 August 2007. The aboveground differential absorption instrument measured an average atmospheric CO(2) concentration of 618 parts per million (ppm) over the CO(2) injection site compared with an average background atmospheric CO(2) concentration of 448 ppm demonstrating this instrument's capability for carbon sequestration site monitoring. The underground differential absorption instrument measured a CO(2) soil gas concentration of 100,000 ppm during the CO(2) injection, a factor of 25 greater than the measured background CO(2) soil gas concentration of 4000 ppm demonstrating this instrument's capability for carbon sequestration site monitoring.

ＣＯ２帯水層貯留での「地層水」の役割とわが国でのＣＯ２地化学トラッピングへの適用性

The geochemical characteristics of deep groundwater, or formation water, are essential in all processes of geochemical trapping in an open aquifer CO2 storage. We have been constructing a database of groundwater chemical compositions in deep aquifers in Japan (“Formation-water database”). The database have two major objectives; (1) to be a dataset on groundwater of reservoir depths for evaluating CO2 solubility; and, (2) providing model water compositions for geochemical modeling and experiments in our study of underground CO2 storage. More than 2600 datasets are collected from literature on geochemistry of groundwater reported from 10 selected areas in Japan; the areas of investigation include populated cities in which large point sources of CO2 are located. The accumulated data indicate that groungwater of reservoir depth (>800m) is generally dilute in composition compared to average seawater, suggesting a high potential of CO2 solubility. Systematic geochemical differences are also observed between groundwater hosted in marine and freshwater sediments.

Lattice-Boltzmann simulation of solvent diffusion into oil-saturated porous media

We simulated the diffusion process into oil-saturated porous media using the modified diffusion-limited aggregation and the lattice Boltzmann method algorithms. The results were matched to visual experiments for cocurrent (two sides of the model open to flow) and countercurrent (only one side of the model open to flow) diffusion for horizontally and vertically positioned samples. The model saturated with oil was exposed to pentane in order for a miscible interaction to take place. These experiments mimic the transfer between the rock matrix and fracture during gas or liquid solvent injection for enhanced oil recovery, underground waste disposal, groundwater contamination, and CO2 sequestration in naturally fractured reservoirs. Finger development at the early stages of the process was controlled by oil viscosity and the interaction type dictated by the boundary conditions. The convective transport driven by the buoyancy that was experimentally observed on vertically oriented samples and transfer driven by diffusion on the horizontal ones were captured in the LBM simulation of the process.

Carbon Capture &amp; Storage: Blue-Sky Technology or Just Blowing Smoke?

Towering 650 feet over the sea surface and spouting an impressive burning flare, it would be easy to mistake the Sleipner West gas platform for an environmental nightmare. Its eight-story upper deck houses 200 workers and supports drilling equipment weighing 40,000 tons. Located off the Norwegian coast, it ranks among Europe’s largest natural gas producers, delivering more than 12 billion cubic feet of the fuel annually to onshore terminals by pipeline. Roughly 9% of the natural gas extracted here is carbon dioxide (CO2), the main culprit behind global warming. But far from a nightmare, Sleipner West is actually a bellwether for environmental innovation. Since 1996, the plant’s operators have stripped CO2 out of the gas on-site and buried it 3,000 feet below the sea floor, where they anticipate it will remain for at least 10,000 years. We believe [CCS] is a viable way to cut global warming pollution. . . . We have the knowledge we need to start moving forward. –David Hawkins, Natural Resources Defense Council Operated by StatoilHydro, Norway’s largest company, Sleipner is among the few commercial-scale facilities in the world today that capture and bury CO2 underground. Many experts believe this practice, dubbed carbon capture and storage (sometimes known as carbon capture and sequestration, but in either case abbreviated CCS), could be crucial for keeping industrial CO2 emissions out of the atmosphere. Sleipner injects 1 million tons of CO2 annually into the Utsira Formation, a saline aquifer big enough to store 600 years’ worth of emissions from all European power plants, company representatives say. With mounting evidence of climate change—and predictions that fossil fuels could supply 80% of global energy needs indefinitely—the spotlight on CCS is shining as brightly as the Sleipner flare. A panel of experts from the Massachusetts Institute of Technology (MIT) recently concluded that CCS is “the critical enabling technology to reduce CO2 emissions significantly while allowing fossil fuels to meet growing energy needs.” The panel’s views were presented in The Future of Coal, a report issued by MIT on 14 March 2007. Environmental groups are split on the issue. Speaking for the Natural Resources Defense Council (NRDC), David Hawkins, director of the council’s Climate Center and a member of the MIT panel’s external advisory committee, says, “We believe [CCS] is a viable way to cut global warming pollution. . . . We have the knowledge we need to start moving forward.” Other environmental groups, including the World Resources Institute, Environmental Defense, and the Pew Center on Global Climate Change, have also come out in support of CCS. These groups view CCS as one among many alternatives (including renewable energy) for reducing CO2 emissions. Greenpeace is perhaps the most vocal critic of CCS. Truls Gulowsen, Greenpeace’s Nordic climate campaigner, stresses that CCS deflects attention from renewable energy and efficiency improvements, which, he says, offer the best solutions to the problem of global warming. “Companies are doing a lot of talking about CCS, but they’re doing little to actually put it into place,” he says. “So, they’re talking about a possible solution that they don’t really want to implement now, and at the same time, they’re trying to push for more coal, oil, and gas development instead of renewables, which we already know can deliver climate benefits.”

Geological Carbon Dioxide Sequestration

A key means of reducing greenhouse gas emissions from fossil fuels is to separate and concentrate CO2 from large point sources and inject it underground. The injection process, so-called “geological carbon sequestration”, uses off-the-shelf technology from the hydrocarbon industry and can be deployed at a useful scale. Widespread deployment will require a greater understanding of processes that trap CO2 underground, improved means of monitoring the injection stream, and a small number of large-scale experiments in settings with the most important representative geology. If successful, geological sequestration could greatly reduce greenhouse gas emissions while we continue to benefit from fossil fuels until true alternatives emerge.

Coupled reservoir–geomechanical analysis of the potential for tensile and shear failure associated with CO 2 injection in multilayered reservoir–caprock systems

Coupled reservoir–geomechanical simulations were conducted to study the potential for tensile and shear failure—e.g., tensile fracturing and shear slip along pre-existing fractures—associated with underground CO 2-injection in a multilayered geological system. This failure analysis aimed to study factors affecting the potential for breaching a geological CO 2-storage system and to study methods for estimating the maximum CO 2-injection pressure that could be sustained without causing such a breach. We pay special attention to geomechanical stress changes resulting from upward migration of the CO 2 and how the initial stress regime affects the potential for inducing failure. We conclude that it is essential to have an accurate estimate of the three-dimensional in situ stress field to support the design and performance assessment of a geological CO 2-injection operation. Moreover, we also conclude that it is important to consider mechanical stress changes that might occur outside the region of increased reservoir fluid pressure (e.g., in the overburden rock) between the CO 2-injection reservoir and the ground surface.

Preparation of CO2-selective separation membranes with highly chemical and thermal stability prepared from inorganic-organic nanohybrids containing branched polyethers

Global warming is becoming an urgent environmental problem. Among CO2 separation processes such as cooling and condensation, solvent scrubbing, adsorption and membrane, membrane separation process is utilized for the flue gas emitting from electric power generation plant; iron works plant and cement plant etc. Another important field is removal of CO2 of natural gas and coal gas [1, 2]. CO2 storage needs to have low environmental impact, low cost and conform to national and international laws. The main optioned for storing CO2 underground which have been examined by the IEA Greenhouse Gas R&D Programme are storage in depleted oil and gas reservoirs, deep saline reservoirs and unminable coal seams [3]. A key technology to attain the membrane separation process is the development of a highly CO2-selective separation membrane with chemical and thermal stability [4]. Recently, active research has been carried out on inorganic-organic nanohybrids prepared by the sol-gel method, which gives products with good thermal and chemical stability and allows formation of high quality membranes [5–8]. Here, nanohybrid means an organic polymer is dispersed at the molecular level in a SiO2 matrix composed of siloxane networks. The most common method to obtain the nanohybrid utilizes hydrogen-bonding interactions between polar functional groups of organic polymers and silanol groups of the silica matrix. Chujo et al. reported that the polymers could be successfully produced without formation of hydrogen bonds between the polymer molecules. For example, poly(2-methyl-2-oxazoline), poly(N-vinylpyrrolidone) etc. could be dispersed in a silica matrix at the molecular level [9]. In the case of the branched polyether, the polymer may be dispersed at the molecular level through hydrogen bonding between the silanol groups of the silica matrix and the polyether oxygens as indicated in Fig. 1. The membrane formed with the branched polyether shows high CO2 selectivity at room temperature (selectivity of CO2 against N2 is 50 at 308 K). However, the selectivity readily decreases at above room temperature [10]. In this paper, we report a CO2-selective inorganic-organic nanohybrid membrane with high chemical and thermal stability prepared from the branched polyether. The typical preparation process of the sol was as follows. To prepare a 5 wt% branched polyether membrane, the sol composition was branched polyether/tetraethoxysilane (TEOS)/acetonitrile = 1:69:465 (weight ratio). The branched polyether was sourced from Daiso Co. Ltd. The molecular weight of the polymer is 520,000 and its molecular structure is shown in Fig. 1. Here, wt% of branched polyether indicates the weight percent of branched polyether relative to the amount of branched polyether and silica hydrolyzed TEOS. Acetonitrile was employed as solvent. In order to perform the hydrolysis, HNO3 and H2O were also added in the following mol ratios: TEOS/HNO3/ H2O = 1:0.01:2. In a typical synthesis, the homogeneous sol was prepared by stirring a mixture of TEOS, T. Yazawa (&) M. Kishimoto T. Inoue A. Mineshige M. Kobune Graduate School of Engineering, University of Hyogo, 2167 Shosha, Himeji-City, Hyogo 671-2201, Japan e-mail: yazawa@eng.u-hyogo.ac.jp

The Atzbach-Schwanenstadt gas field—a potential site for onshore CO2 storage and EGR

As a part of the EU-supported CASTOR project, four sites for potential or actual underground CO2 sequestration in Europe are being investigated. One of these sites is Atzbach-Schwanenstadt gas field in Upper Austria, operated by Rohol-Aufsuchungs AG. The CASTOR project is a feasibility study which aims:

Health, Safety and Environmental Risks of Underground Co2 Storage – Overview of Mechanisms and Current Knowledge

CO2 capture and storage (CCS) in geological reservoirs may be part of a strategy to reduce global anthropogenic CO2 emissions. Insight in the risks associated with underground CO2 storage is needed to ensure that it can be applied as safe and effective greenhouse mitigation option. This paper aims to give an overview of the current (gaps in) knowledge of risks associated with underground CO2 storage and research areas that need to be addressed to increase our understanding in those risks. Risks caused by a failure in surface installations are understood and can be minimised by risk abatement technologies and safety measures. The risks caused by underground CO2 storage (CO2 and CH4 leakage, seismicity, ground movement and brine displacement) are less well understood. Main R&D objective is to determine the processes controlling leakage through/along wells, faults and fractures to assess leakage rates and to assess the effects on (marine) ecosystems. Although R&D activities currently being undertaken are working on these issues, it is expected that further demonstration projects and experimental work is needed to provide data for more thorough risk assessment.

The low cost of geological assessment for underground CO2 storage: Policy and economic implications

The costs for carbon dioxide (CO2) capture and storage (CCS) in geologic formations is estimated to be $6–75/t CO2. In the absence of a mandate to reduce greenhouse gas emissions or some other significant incentive for CCS deployment, this cost effectively limits CCS technology deployment to small niche markets and stymies the potential for further technological development through learning by doing until these disincentives for the free venting of CO2 are in place. By far, the largest current fraction of these costs is capture (including compression and dehydration), commonly estimated at $25–60/t CO2 for power plant applications, followed by CO2 transport and storage, estimated at $0–15/t CO2. Of the storage costs, only a small fraction of the cost will go to accurate geological characterization. These one time costs are probably on the order of $0.1/t CO2 or less as these costs are spread out over the many millions of tons likely to be injected into a field over many decades. Geologic assessments include information central to capacity prediction, risk estimation for the target intervals and development facilities engineering. Since assessment costs are roughly two orders of magnitude smaller than capture costs, and assessment products carry other tangible societal benefits, such as improved accuracy in fossil fuel and ground water reserves estimates, government or joint private–public funding of major assessment initiatives should underpin early policy choices regarding CO2 storage deployment and should serve as a point of entry for policy makers and regulators. Early assessment is also likely to improve the knowledge base upon which the first commercial CCS deployments will rest.

Nanoscale surface observation of feldspar dissolved under supercritical CO 2–water–mineral system

As part of our assessment program on underground CO 2 storage, we studied the dissolution of feldspar in aqueous solutions of supercritical CO 2 at 25, 50, 65, and 80 °C with a constant CO 2 pressure of 10 MPa. Atomic force microscopy (AFM) was then used to observe nanoscale dissolution features on the feldspar surface. The average dissolution rates of anorthite during the initial 1 week of dissolution were estimated from surface retreat based on vertical cross-section profiles.