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.     

Power generation with CO2 capture: Technology for CO2 purification

The goal of this paper is to find methodologies for removing a selection of impurities (H₂O, O₂, Ar, N₂, SO_x and NO_x) from CO₂ present in the flue gas of two oxy-combustion power plants fired with either natural gas (467 MW) or pulverized fuel (596 MW). The resulting purified stream, containing mainly CO₂, is assumed to be stored in an aquifer or utilized for enhanced oil recovery (EOR) purposes. Focus has been given to power cycle efficiency i.e.: work and heat requirements for the purification process, CO₂ purity and recovery factor (kg of CO₂ that is sent to storage per kg of CO₂ in the flue gas). Two different methodologies (here called Case I and Case II) for flue gas purification have been developed, both based on phase separation using simple flash units (Case I) or a distillation column (Case II). In both cases purified flue gas is liquefied and its pressure brought to 110 atm prior to storage.Case I: A simple flue gas separation takes place by means of two flash units integrated in the CO₂ compression process. Heat in the process is removed by evaporating the purified liquid CO₂ streams coming out from both flashes. Case I shows a good performance when dealing with flue gases with low concentration of impurities. CO₂ fraction after purification is over 96% with a CO₂ recovery factor of 96.2% for the NG-fired flue gas and 88.1% for the PF-fired flue gas. Impurities removal together with flue gas compression and liquefaction reduces power plant output of 4.8% for the NG-fired flue gas and 11.6% for the PF-fired flue gas. The total amount of work requirement per kg stored CO₂ is 453 kJ for the NG-fired flue gas and 586 kJ for the PF-fired flue gas.Case II: Impurities are removed from the flue gas in a distillation column. Two refrigeration loops (ethane and propane) have been used in order to partially liquefy the flue gas and for heat removal from a partial condenser. Case II can remove higher amounts of impurities than Case I. CO₂ purity prior to storage is over 99%; CO₂ recovery factor is somewhat lower than in Case I: 95.4% for the NG-fired flue gas and 86.9% for the PF-fired flue gas, reduction in the power plant output is similar to Case I.Due to the lower CO₂ recovery factor the total amount of work per kg stored CO₂ is somewhat higher for Case II: 457 kJ for the NG-fired flue gas and 603 kJ for the PF-fired flue gas.     

An engineering-economic model of pipeline transport of CO2 with application to carbon capture and storage

Carbon dioxide capture and storage (CCS) involves the capture of CO₂ at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO₂ is sequestered. Previous work has identified pipeline transport of liquid CO₂ as the most economical method of transport for large volumes of CO₂. However, there is little published work on the economics of CO₂ pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO₂ over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO₂ transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO₂ transported for a 100 km pipeline constructed in the Midwest handling 5 million tonnes of CO₂ per year (the approximate output of an 800 MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO₂ for a 100 km pipeline, and US$ 4.06 per tonne CO₂ for a 200 km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO₂ is between US$ 1.03 and US$ 2.63 per tonne of CO₂ transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing.     

Methodology for CO2 chain analysis

The paper presents a methodology for CO₂ chain analysis with particular focus on the impact of technology development on the total system economy. The methodology includes the whole CO₂ chain; CO₂ source, CO₂ capture, transport and storage in aquifers or in oil reservoirs for enhanced oil recovery. It aims at supporting the identification of feasible solutions and assisting the selection of the most cost-effective options for carbon capture and storage. To demonstrate the applicability of the methodology a case study has been carried out to illustrate the possible impact of technology improvements and market development. The case study confirms that the CO₂-quota price to a large extent influence the project economy and dominates over potential technology improvements. To be economic feasible, the studied chains injecting the CO₂ in oil reservoirs for increased oil production require a CO₂-quota price in the range of 20–27 €/tonne CO₂, depending on the technology breakthrough. For the chains based on CO₂ storage in saline aquifers, the corresponding CO₂-quota price varies up to about 40 €/tonne CO₂.     

Viscosities, thermal conductivities and diffusion coefficients of CO2 mixtures: Review of experimental data and theoretical models

Accurate experimental data on the thermo-physical properties of CO₂-mixtures are pre-requisites for development of more accurate models and hence, more precise design of CO₂ capture and storage (CCS) processes. A literature survey was conducted on both the available experimental data and the theoretical models associated with the transport properties of CO₂-mixtures within the operation windows of CCS. Gaps were identified between the available knowledge and requirements of the system design and operation. For the experimental gas-phase measurements, there are no available data about any transport properties of CO₂/H₂S, CO₂/COS and CO₂/NH₃; and except for CO₂/H₂O(/NaCl) and CO₂/amine/H₂O mixtures, there are no available measurements regarding the transport properties of any liquid-phase mixtures. In the prediction of gas-phase viscosities using Chapman–Enskog theory, deviations are typically <2% at atmospheric pressure and moderate temperatures. The deviations increase with increasing temperatures and pressures. Using both the Rigorous Kinetic Theory (RKT) and empirical models in the prediction of gas-phase thermal conductivities, typical deviations are 2.2–9%. Comparison of popular empirical models for estimation of gas-phase diffusion coefficients with newer experimental data for CO₂/H₂O shows deviations of up to 20%. For many mixtures relevant for CCS, the diffusion coefficient models based on the RKT show predictions within the experimental uncertainty. Typical reported deviations of the CO₂/H₂O system using empirical models are below 3% for the viscosity and the thermal conductivity and between 5 and 20% for the diffusion coefficients. The research community knows little about the effect of other impurities in liquid CO₂ than water, and this is an important area to focus in future work.     

A model for the CO2 capture potential

Global warming is a result of increasing anthropogenic CO₂ emissions, and the consequences will be dramatic climate changes if no action is taken. One of the main global challenges in the years to come is therefore to reduce the CO₂ emissions.Increasing energy efficiency and a transition to renewable energy as the major energy source can reduce CO₂ emissions, but such measures can only lead to significant emission reductions in the long-term. Carbon capture and storage (CCS) is a promising technological option for reducing CO₂ emissions on a shorter time scale.A model to calculate the CO₂ capture potential has been developed, and it is estimated that 25 billion tonnes CO₂ can be captured and stored within the EU by 2050. Globally, 236 billion tonnes CO₂ can be captured and stored by 2050. The calculations indicate that wide implementation of CCS can reduce CO₂ emissions by 54% in the EU and 33% globally in 2050 compared to emission levels today.Such a reduction in emissions is not sufficient to stabilize the climate. Therefore, the strategy to achieve the necessary CO₂ emissions reductions must be a combination of (1) increasing energy efficiency, (2) switching from fossil fuel to renewable energy sources, and (3) wide implementation of CCS.     

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

Corrosion and polarization behavior of carbon steel in MEA-based CO2 capture process

This work reveals levels of corrosion rate and polarization behavior of carbon steel immersed in aqueous solutions of monoethanolamine (MEA) used in the absorption-based carbon dioxide (CO₂) capture process for greenhouse gas reduction from industrial flue gas streams. Such information was obtained from electrochemical-based corrosion experiments under a wide range of the CO₂ capture process conditions. The corrosion of carbon steel was evaluated in respect to process parameters including partial pressure of oxygen (O₂), CO₂ loading in solution, solution velocity, solution temperature, MEA concentration and metal surface condition. Results show that the aqueous MEA solution containing CO₂ provides a favorable condition for the corrosion of carbon steel to proceed. Corrosion rate is increased by all tested process parameters. These parametric effects were explained by the electrochemical kinetic data obtained from polarization curves and by the thermodynamic data obtained from Pourbaix diagram.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

Screening and selection of sites for CO2 sequestration based on pressure buildup

This paper presents a simple methodology for estimating pressure pressure buildup due to the injection of supercritical CO₂into a saline formation, and the limiting pressure at which the formation starts to fracture. Pressure buildup is calculated using the approximate solution of Mathias et al. [Mathias, S.A., Hardisty, P.E., Trudell, M.R., Zimmerman, R.W., 2009. Approximate solutions for pressure buildup during CO₂ injection in brine aquifers. Transp. Porous Media. doi:10.1007/s11242-008-9316-7], which accounts for two-phase Forchheimer flow (of supercritical CO₂ and brine) in a compressible porous medium. Compressibility of the rock formation and both fluid phases are also accounted for. Injection pressure is assumed to be limited by the pressure required to fracture the rock formation. Fracture development is assumed to occur when pore pressures exceed the minimum principal stress, which in turn is related to the Poisson’s ratio of the rock formation. Detailed guidance is also offered concerning the estimation of viscosity, density and compressibility for the brine and CO₂. Example calculations are presented in the context of data from the Plains CO₂ Reduction (PCOR) Partnership. Such a methodology will be useful for screening analysis of potential CO₂ injection sites to identify which are worthy of further investigation.     

Comparison of several packings for CO2 chemical absorption in a packed column

CO₂ capture and storage has gained widespread attention as an option for reducing greenhouse gas emissions. Chemical absorption and stripping of CO₂ with hot potassium carbonate (K₂CO₃) solutions has been used in the past, however potassium carbonate solutions have a low CO₂ absorption efficiency. Various techniques can be used to improve the absorption efficiency of this system with one option being the addition of promoters to the solvent and another option being an improvement in the mass transfer efficiency of the equipment. This study has focused on improving the efficiency of the packed column by replacing traditional packings with newer types of packing which have been shown to have enhanced mass transfer performance. Three different packings (Super Mini Rings (SMRs), Pall Rings and Mellapak) have been studied under atmospheric conditions in a laboratory scale column for CO₂ absorption using a 30 wt% K₂CO₃ solution. It was found that SMR packing resulted in a mass transfer coefficient approximately 20% and 30% higher than that of Mellapak and Pall Rings, respectively. Therefore, the height of packed column with SMR packing would be substantially lower than with Pall Rings or Mellapak. Meanwhile, the pressure drop using SMR was comparable to other packings while the gas flooding velocity was higher when the liquid load was above 25 kg m⁻² s⁻¹. Correlations for predicting flooding gas velocities and pressure drop were fitted to the experimental data, allowing the relevant parameters to be estimated for use in later design.     

Laboratory calibration of the seismo-acoustic response of CO2 saturated sandstones

Ultrasonic experiments were undertaken on CO₂ flooded sandstone core samples, both synthetic sandstones and core plugs from the CRC1 CO₂ injection well in the Otway Basin, Victoria, South Eastern. Australia. The aim of these laboratory tests was to investigate the effects of CO₂ as a pore fluid on the seismo-acoustic response of the sandstone and ultimately to provide an indication of the sensitivity of time-lapse seismic imaging of the eventual CO₂/CH₄ plume in the Otway, Waarre C formation.The synthetic sandstones were manufactured using both a proprietary calcium in situ precipitation (CIPS) process and a silica cementing technique. Samples were tested in a computer controlled triaxial pressure cell where pore pressures can be controlled independently of the confining pressures. The pressure cell is equipped with ultrasonic transducers housed in the loading platens. Consequently, effective pressures equivalent to those expected in the reservoir can be applied while ultrasonic testing is undertaken. Both compressional, P and shear waves, S were recorded via a digital oscilloscope at a range of effective pressure steps. Pore pressures were varied from 4 MPa to 17 MPa to represent both the gaseous and liquid phase regions of the CO₂ phase diagram. Similar experiments were conducted on core plugs from the Waarre C reservoir horizon obtained from the CRC1 injection well, but with an intervening brine-saturated step and in some cases with a CO₂/CH₄ mix of 80%/20% molar fraction which is representative of the field situation. However, the pore pressure in these experiments was held at 4 MPa. Finally, acoustic impedances and reflection coefficients were calculated for the reservoir using Gassmann theory and the implications for imaging the CO₂ plume is discussed.     

The impact of heterogeneity on the distribution of CO2: Numerical simulation of CO2 storage at Ketzin

Numerical modelling of multiphase flow is an essential tool to ensure the viability of long-term and safe CO₂ storage in geological formations. Uncertainties arising from the heterogeneity of the formation and lack of knowledge of formation properties need to be assessed in order to create a model that can reproduce the data available from monitoring. In this study, we investigated the impact of unknown spatial variability in the petrophysical properties within a sandy channel facies of a fluviatile storage formation using stochastic methods in a Monte Carlo approach. The stochastic method has been applied to the Ketzin test site (CO₂SINK), and demonstrates that the deterministic homogeneous model satisfactorily predicts the first CO₂ arrival time at the Ketzin site. The equivalent permeability was adjusted to the injection pressure and is in good agreement with the hydraulic test. It has been shown that with increasing small-scale heterogeneity, the sharpness of the CO₂ front decreases and a greater volume of the reservoir is affected, which is also seen in an increased amount of dissolved CO₂. Increased anisotropy creates fingering effects, which result in higher probabilities for earlier arrival times. Generally, injectivity decreases with increasing heterogeneity.     

Study on the failure mechanism of potassium-based sorbent for CO2 capture and the improving measure

With thermogravimetric apparatus (TGA), X-ray diffraction (XRD) and barium sulfate gravimetric methods, the carbonation reactivities of K₂CO₃ and K₂CO₃/Al₂O₃ in the simulated flue gases with SO₂ are investigated and the reaction equations are inferred. Results show that there are KHCO₃ and K₂SO₃ generated. The generation K₂SO₃ reduces the utilization ratio of the sorbent. H₂O may accelerates the sulfation reaction of AR K₂CO₃ as K₄H₂(CO₃)₃·1.5H₂O is generated in the reaction among K₂CO₃, SO₂ and H₂O. K₂SO₃ is directly generated from sulfation reaction of K₂CO₃/Al₂O₃, because there are K₂CO₃·1.5H₂O and K₂SO₃ generated in the reaction among K₂CO₃/Al₂O₃, SO₂ and H₂O. K₂CO₃·1.5H₂O does not react with SO₂, and K₂CO₃·1.5H₂O/Al₂O₃ reacts with SO₂ slowly. Compare with the reaction process without H₂O pretreatment, the reaction rates of KAl30 increased after H₂O pretreatment and the failure ratio is about a half of that without H₂O pretreatment. So, K₂CO₃/Al₂O₃ shows good carbonation and anti-sulfation characteristic after H₂O pretreatment.     

Numerical parametric study on CO2 capture by indirect thermal swing adsorption

Post-combustion CO₂ capture remains one of the most-challenging issue to lower CO₂ emissions of existing power plants or heavy industry installations because of strong economy and energy efficiency aspects. The major issue comes from CO₂ dilution (4% for NGCC and 14% for PC) and the high flow rates to be treated. Furthermore, CO₂ purity has to be higher than 95% with recovery at 90%, to match the transportation/injection requirements.The MEA absorption process remains the reference today but its energy consumption (about 3 MJ/kg_CO2) and the amine consumption are still challenging drawbacks.The interest of CO₂ capture by indirect TSA (Temperature Swing Adsorption) was demonstrated experimentally in a previous work. The aim of this paper is to present the results of a numerical parametric study. Two main parameters are explored: the desorption temperature (100–200 °C) and the purge flow rate (0.1–0.5 Ndm³ min⁻¹). Four performance indicators are evaluated: CO₂ purity, recovery, productivity and specific energy consumption.Results show that purity above 95% can be achieved. Keeping the 95% target, it is possible to achieve recovery at 81% with productivity at 57.7 g_CO2/kg_ads h and a specific energy consumption of 3.23 MJ/kg_CO2, which is less than for the reference MEA process.Comparison with other adsorption processes exhibits that this process has good potential especially since some improvements are still expected from further research.     

Coupled hydromechanical modeling of CO2 sequestration in deep saline aquifers

Sequestration of carbon dioxide (CO₂) in deep saline aquifers has emerged as an option for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO₂ that need to be injected into deep saline aquifers may cause large fluid pressure increases. The resulting overpressure may promote reactivation of sealed fractures or the creation of new ones in the caprock seal. This could lead to escape routes for CO₂. In order to assess the probability of such an event, we model an axisymmetric horizontal aquifer–caprock system, including hydromechanical coupling. We study the failure mechanisms, using a viscoplastic approach. Simulations illustrate that, depending on boundary conditions, the least favorable moment takes place at the beginning of injection. Initially, fluid pressure rises sharply because of a reduction in permeability due to desaturation. Once CO₂ fills the pores in the vicinity of the injection well and a capillary fringe is fully developed, the less viscous CO₂ displaces the brine and the capillary fringe laterally. The overpressure caused by the permeability reduction within the capillary fringe due to desaturation decreases with distance from the injection well. This results in a drop in fluid pressure buildup with time, which leads to a safer situation. Nevertheless, in the presence of low-permeability boundaries, fluid pressure continues to rise in the whole aquifer. This occurs when the radius of influence of the injection reaches the outer boundary. Thus, caprock integrity might be compromised in the long term.     

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.     

Highly siliceous MCM-48 from rice husk ash for CO2 adsorption

Mesoporous MCM-48 silica was synthesized using a cationic-neutral surfactant mixture as the structure-directing template and rice husk ash (RHA) as the silica source. The MCM-48 samples were characterized by X-ray powder diffraction (XRD), Fourier transform infrared spectroscopy (FT-IR), N₂ physisorption and SEM. X-ray diffraction pattern of the resulting MCM-48 revealed typical pattern of cubic Ia3d mesophase. BET results showed the MCM-48 to have a surface area of 1024 m²/g and FT-IR revealed a silanol functional group at about 3460 cm⁻¹. Breakthrough experiments in the presence of MCM-48 were also carried out to test the material's CO₂ adsorption capacity. The breakthrough time for CO₂ was found to decrease as the temperature increased from 298 K to 348 K. The steep slopes observed shows the CO₂ adsorption occurred very quickly, with only a minimal mass transfer effect and very fast kinetics. In addition, amine grafted MCM-48, APTS-MCM-48 (RHA), was prepared with the 3-aminopropyltriethoxysilane (APTS) to investigate the effect of amine functional group in CO₂ separation. An order of magnitude higher CO₂ adsorption capacity was obtained in the presence of APTS-MCM-48 (RHA) compared to that with MCM-48 (RHA). These results suggest that MCM-48 synthesized from rice husk ash could be usefully applied for CO₂ removal.     

Electric Swing Adsorption for CO2 removal from flue gases

One of the most important sources of CO₂ emissions are the fossil-fuel fired plants for production of electricity. Removal of CO₂ from flue gas streams for further sequestration has been proposed by the International Panel on Climate Change experts as one of the most reliable solutions to mitigate anthropogenic greenhouse emissions. When natural gas is employed as fuel, the molar fraction of CO₂ in the flue gas is lower than 5% causing serious problems for capture. The purpose of this work is to present experimental validation of an Electric Swing Adsorption (ESA) technology that may be employed for carbon capture for low molar fractions of CO₂ in the flue gas streams. To improve energy utilization, an activated carbon honeycomb monolith with low electrical resistivity was employed as selective adsorbent. A mathematical model for this honeycomb is proposed as well as different ESA cycles for CO₂ capture.     

Geochemical and solute transport modelling for CO2 storage, what to expect from it?

Geochemistry plays an important role when assessing the impact of CO₂ storage. Due to the potential corrosive character of CO₂, it might affect the chemical and physical properties of the wells, the reservoir and its surroundings and increase the environmental and financial risk of CO₂ storage projects in deep geological structures. An overview of geochemical and solute transport modelling for CO₂ storage purposes is given, its data requirements and gaps are highlighted, and its progress over the last 10 years is discussed. Four different application domains are identified: long-term integrity modelling, injectivity modelling, well integrity modelling and experimental modelling and their current state of the art is discussed. One of the major gaps remaining is the lack of basic thermodynamical and kinetic data at relevant temperature and pressure conditions for each of these four application domains. Real challenges are the coupled solute transport and geomechanical modelling, the modelling of impurities in the CO₂ stream and pore-scale modelling applications.