International Journal of Greenhouse Gas Control

Calcium looping (CaL) is a promising post-combustion CO2 capture technology which is carried out in a dual fluidized bed (DFB) system with continuous looping of CaO, the CO2 carrier, between two beds. The system consists of a carbonator, where flue gas CO2 is adsorbed by CaO and a regenerator, where captured CO2 is released. The CO2-rich regenerator flue gas can be sequestered after gas processing and compression. A parametric study was conducted on the 10 kWth DFB facility at the University of Stuttgart, which consists of a bubbling fluidized bed carbonator and a riser regenerator. The effect of the following parameters on CO2 capture efficiency was investigated: carbonator space time, carbonator temperature and calcium looping ratio. The active space time in the carbonator, which is a function of the space time and the calcium looping ratio, was found to strongly correlate with the CO2 capture efficiency. BET and BJH techniques provided surface area and pore volume distribution data, respectively, for collected sorbent samples. The rate of sorbent attrition was found to be 2 wt.%/h which is below the expected sorbent make-up rate required to maintain sufficient sorbent activity. Steady-state CO2 capture efficiencies greater than 90% were achieved for different combinations of operational parameters. Moreover, the experimental results obtained were briefly compared with results derived from reactor modeling studies. Finally, the implications of the experimental results with respect to commercialization of the CaL process have been assessed.

In this study, first operating experience with a 120 kW chemical looping pilot rig is presented. The dual circulating fluidized bed reactor system and its auxiliary units are discussed. Two different oxygen carries, i.e. ilmenite, which is a natural iron titanium ore and a designed Ni-based particle, are tested in the CLC unit. The pilot rig is fueled with H2, CO and CH4 respectively at a fuel power of 65–145 kW. High solids circulation, very low solids residence time and low solids inventory are observed during operation. Due to the scalability of the design concept, these characteristics should be quite similar to those of commercial CLC power plants. Ilmenite shows a high potential for the combustion of H2 rich gases (e.g. from coal gasification with steam). The H2 conversion is quite high but there is still a high potential for further improvement. The Ni-based oxygen carrier achieves the thermodynamic maximum H2 and CO conversion and also very high CH4 conversion. A variation of the air/fuel ratio and the reaction temperature indicates that the Ni/NiO ratio of the particle has a high influence on the performance of the chemical looping combustor.

This paper investigates the role of CCS technologies as part of a portfolio for reducing CO2 emissions from the European electricity supply system until the year 2050. The analysis is carried out with the aid of a techno-economic model (with the objective to minimize the total system cost) including a detailed description of the present stationary European electricity supply system (power plants) and potential CO2 storage sites as obtained from the Chalmers Energy Infrastructure databases. The ability of different EU Member States and regions to facilitate and to benefit from CCS will most likely depend on local conditions in terms of current energy mix, fuel supply chains and distance to suitable storage locations. Special emphasis is therefore put on analyzing turn-over in capital stock of the existing power plant infrastructure, timing of investments and the infrastructural implications of large scale introduction of CCS on a regional perspective. The paper discusses the role of and the requirements on CCS for meeting strict CO2 emission reduction targets of 85% reduction from power generation by 2050 relative 1990 emissions in three different scenarios. All analysed scenarios apply the same cap on CO2 emissions. The first scenario includes a continued growth in electricity demand (as presented in EU base-line projections). The second scenario includes stated EU targets for 2020 and indicative targets for 2050 with respect to increased energy efficiency, and thus, considers a lower growth in electricity demand compared to the base-line. The third scenario includes EU targets (to 2020 and indicative targets to 2050) on energy efficiency, equal to the second scenario, and EU targets of electricity from renewables.

New comprehensive numerically solved 1D and 2D absorption rate/kinetics models have been developed, for the first time, to interpret the experimental kinetic data obtained with a laminar jet apparatus for the absorption of carbon dioxide (CO2) in CO2 loaded mixed solutions of mixed amine system of methyldiethanolamine (MDEA) and monoethanolamine (MEA). Three MDEA/MEA weight ratios ranging from 27/03 to 23/07, over a concentration range of 2.316–1.996 kmol/m3 for MDEA and of 0.490–1.147 kmol/m3 for MEA were studied. The models take into account the coupling between chemical equilibrium, mass transfer, and the chemical kinetics of all possible chemical reactions involved in the CO2 reaction with MDEA/MEA solvent. The partial differential equations of the 1D model were solved by two numerical techniques; the finite difference method (FDM) based on in-house coded Barakat–Clark scheme and the finite element method (FEM) based on COMSOL software. The FEM comprehensive model was then used to solve the set of partial differential equations in the 2D cylindrical coordinate system setting. Both FDM and FEM produced very accurate results for both the 1D and 2D models, which were much better than our previously published simplified model. The reaction rate constant obtained for MEA blended into MDEA at 298–333 K was kMEA = 5.127 × 108 exp(−3373.8/T). In addition, the 2D model, for the first time, has provided the concentration profiles of all the species in both the radial and axial directions of the laminar jet, thereby enabling an understanding of the correct sequence in which the reaction steps involved in the reactive absorption of CO2 in aqueous mixed amines occur.

CO2 injection into a depleted hydrocarbon field or aquifer may give rise to a variety of coupled physical and chemical processes. During CO2 injection, the increase in pore pressure can induce reservoir expansion. As a result the in situ stress field may change in and around the reservoir. The geomechanical behaviour induced by oil production followed by CO2 injections into an oil field reservoir in the Paris Basin has been numerically modelled. This paper deals with an evaluation of the induced deformations and in situ stress changes, and their potential effects on faults, using a 3D geomechanical model. The geomechanical analysis of the reservoir–caprock system was carried out as a feasibility study using pressure information in a “one way” coupling, where pressures issued from reservoir simulations were integrated as input for a geomechanical model. The results show that under specific assumptions the mechanical effects of CO2 injection do not affect the mechanical stability of the reservoir–caprock system. The ground vertical movement at the surface ranges from −2 mm during oil production to +2.5 mm during CO2 injection. Furthermore, the changes in in situ stresses predicted under specific assumptions by geomechanical modelling are not significant enough to jeopardize the mechanical stability of the reservoir and caprock. The stress changes issued from the 3D geomechanical modelling are also combined with a Mohr–Coulomb analysis to determine the fault slip tendency. By integrating the stress changes issued from the geomechanical modelling into the fault stability analysis, the critical pore pressure for fault reactivation is higher than calculated for the fault stability analysis considering constant horizontal stresses.

A post-combustion CO2 capture process intended for offshore operations has been designed and optimised for integration with a natural gas-fired power plant on board a floating structure developed by the Norway-based company Sevan Marine ASA—designated Sevan GTW (gas-to-wire). The concept is constrained by the structure of the floater carrying a SIEMENS modular power system rated at 450 MWe, with a capture rate of 90% and CO2 compression (1.47 Mtpa) for pipeline pressure at 12 MPa. A net efficiency of 45% (based on a lower heating value) is estimated for the system with CO2 capture, thus suggesting that the post-combustion CO2 capture system is accountable for a fuel penalty of nine percentage points.The rationale behind the technology selection is the urgency of replacing the dispersed aero-derivative gas turbines which power the offshore oil and gas production units in Norwegian waters with near-zero emission power.As (inherently) fresh water usually constitutes a limiting factor in sea operations, efforts are made to obtain a neutral water balance to obtain an optimal design. This is primarily achieved by controlling the cleaned flue gas temperature at the top of the absorber column.

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.

Laypeople's acceptance and perception of Carbon Dioxide Capture and Storage (CCS) can have an influence on its political feasibility. It is important, therefore, to study how laypeople perceive CCS and which cognitions they hold with respect to this technique. We conducted in-depth interviews with laypeople (N = 16) to explore their mental concepts of CCS. Little knowledge about CCS was detected among laypeople. We also found that laypeople fear that a deployment of CCS could create incentives that would hinder a sustainable development of the energy economy. A misunderstanding of the concepts of hydro- and geostatic pressure, as well as a lack of knowledge about the physical–chemical properties of carbon dioxide seemed to trigger fundamental rejection of CCS among some laypeople. This qualitative study identifies concepts that underlie CCS perception, and these should be objects of future studies. We provide some suggestions for risk management and communication about CCS.

The application of membrane gas separation to CO2 capture from a coal gasification process is one potential solution to reduce greenhouse gas emissions. This review considers the potential for either H2- or CO2-selective membranes in an integrated gasification combined cycle (IGCC) process. In particular, the advantages and disadvantages of metallic, porous inorganic and polymeric membranes are considered. This analysis is extended to consider membrane technology as an enhancement to the water-gas shift reaction, to drive the production of hydrogen above the thermodynamic limit. The review concludes with a brief overview of the economics of incorporating membrane gas separation into the IGCC process and gives an indication of the potential economic use of membrane gas separation technology in the IGCC process.

Chemical absorption of CO2 is deemed as an effectively controllable way to accomplish large reduction of greenhouse gas emission. A two dimensional (2-D) model for two-phase flows is established for chemical absorption of CO2 in the packed column. A good agreement has been reached between the simulated temperature and fluid flow profiles and experimental results. The field synergy equations are deduced to optimize the fluid flow, mass transfer, heat transfer and chemical reaction by an established Lagrange function. The synergy angle is an index to express the synergy degree among the physical phenomena. The global field synergy optimized velocity field, temperature distribution and gas concentration variation trend are obtained, contributing to improvement of 9% CO2 removal efficiency. Meanwhile, the entropy generation rate was well applied to quantify the overall improvement from the perspective of exergy. The results indicated that the entropy generation rate induced by mass transfer and reaction composes the most part of the irreversibility. The exergy loss is reduced by 12.8% after global field synergy optimization mainly for the two resistances reduction. The results showed that the field synergy optimization could be an intensification method for CO2 capture, whose improvement effect could be assessed by entropy generation analysis.

Studies of the kinetics of sulfur dioxide (SO2)- and oxygen (O2)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO2) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O2, SO2 and CO2. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO2 absorption process (3–7 kmol/m3 MEA, 6% O2, 0–196 ppm SO2, 0–0.55 CO2 loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O2 and SO2 resulted in a higher MEA degradation rate. An increase in CO2 concentration gave the opposite effect. A semi-empirical model based on the initial rate, −rMEA = {6.74 × 109 e−(29,403/RT)[MEA]0.02([O]2.91 + [SO2]3.52)}/{1 + 1.18[CO2]0.18} was developed to fit the experimental data. With the higher order of reaction, SO2 has a higher propensity to cause MEA to degrade than O2. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O2, SO2, and CO2) can be removed without affecting the usability of the model.

A novel CO2 separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO2 absorption after which hydrated CO2 reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO2-loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO2-bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO2-bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO2-bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO2-bearing capacity of PABB was 1.37 mol of CO2 per kg dry bead. TGA was also used to assess the regenerability of CO2-loaded PABB. Preliminary results suggest that CO2 is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO2 dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed.

The carbon dioxide capture potential of amine amino acid salts (AAAS), formed by mixing equinormal amounts of amino acids; e.g. glycine, β-alanine and sarcosine, with an organic base; 3-(methylamino)propylamine (MAPA), was assessed by comparison with monoethanolamine (MEA), and with amino acid salt (AAS) from amino acid neutralized with an inorganic base; potassium hydroxide (KOH). Carbon dioxide absorption and desorption experiments were carried out on the solvent systems at 40 °C and 80 °C respectively. Experimental results showed that amine amino acid salts have similar CO2 absorption properties to MEA of the same concentration. They also showed good signs of stability during the experiments. Amino acid salt from an inorganic base, KOH, showed lower performance in CO2 absorption than the amine amino acid salts (AAAS) mainly due to a lower equilibrium temperature sensitivity. AAAS showed better performance than MEA of same concentration. AAAS from neutralization of sarcosine with MAPA showed the best performance and the performance could be further enhanced when promoted with excess MAPA. The solvent comparison is semi-quantitative since the bubble structure, and thus gas–liquid interfacial area may not be the same for all experiments, however superficial gas velocities were kept constant.

The simulation tool ASPEN Plus® is used to model the full CO2-capture process for chemical absorption of CO2 by piperazine-promoted potassium carbonate (K2CO3/PZ) and the subsequent CO2-compression train. Sensitivity analysis of lean loading, desorber pressure and CO2-capture rate are performed for various solvent compositions to evaluate the optimal process parameters. EbsilonProfessional® is used to model a 600 MWel (gross) hard coal-fired power plant. Numerical equations for power losses due to steam extraction for solvent regeneration are derived from simulation runs. The results of the simulation campaigns are used to find the process parameters that show the lowest specific power loss. Subsequently, absorber and desorber columns are dimensioned to evaluate investment costs for these main components of the CO2-capture process. Regeneration heat duty, net efficiency losses and column investment costs are then compared to the reference case of CO2-capture by monoethanolamine (MEA).CO2-capture by piperazine-promoted potassium carbonate with subsequent CO2-compression to 110 bar shows energetic advantages over the reference process which uses MEA. Additionally, investment costs for the main components in the CO2-capture process (absorber and desorber columns) are lower due to the enhanced reaction kinetics of the investigated K2CO3/PZ solvent which leads to smaller component sizes.

This study assesses potential environmental impacts of the absorption-based carbon dioxide (CO2) capture unit that is integrated to coal-fired power plant for post-combustion treatment of flue gas. The assessment was performed by identifying potential pollutants and their sources as well as amounts of emissions from the CO2 capture unit and also by reviewing toxicology, potential implications to human health and the environment, as well as the environmental laws and regulations associated with such pollutants. The assessment shows that, while offering a significant environmental benefit through a reduction of greenhouse gas emissions, the installation of CO2 capture units for post-combustion treatment might induce unintentional and potential burdens to human health and the environment through four emission pathways, including treated gas, process wastes, fugitive emissions, and accidental releases. Such burdens nevertheless can be predetermined and properly mitigated through a well-established environmental management program and mitigation measures. Recommendations to minimize these impacts are provided in this paper.

The present work is a study to evaluate ionic liquids as a potential solvent for post-combustion CO2 capture. In order to enhance the absorption performance of a CO2 capture unit, different ionic liquids have been designed and tested. The main goal was to get a comparison between a reference liquid and selected ionic liquids. As the reference, a solution of 30 w% monoethanolamine (MEA) and water was used. A large range of different pure and diluted ionic liquids was tested with a special screening process to gain general information about the CO2 absorption performance. Based on these results, a 60 w% ionic liquid solution in water was selected and the vapour–liquid equilibrium was measured experimentally between 40 °C and 110 °C. From these curves the enthalpy of absorption for capturing CO2 into the ionic liquid was determined. With these important parameters one is able to calculate the total energy demand for stripping of CO2 from the loaded solvent for comparison of the ionic liquid based solvent with the reference MEA solvent. The energy demand of this 60 w% ionic liquid is slightly lower than that of the reference solution, resulting in possible energy savings between 12 and 16%.

We performed a detailed analysis of the potential future costs and performance of post-combustion CO2 absorption in combination with a natural gas combined cycle (NGCC). After researching state-of-the-art technology, an Excel model was created to analyze possible developments in the performance of energy conversion, CO2 capture, and CO2 compression. The input variables for the three time frames we used were based on literature data, product information, expert opinions, and our own analysis. Using a natural gas price of 4.7 €/GJ, we calculated a potential decrease in the costs of electricity from 5.6 €ct/kWh in the short term to 4.8 €ct/kWh in the medium term and 4.5 €ct/kWh in the long term. The efficiency penalty is calculated to decline from 7.9%-points LHV in the short term to 4.9%-points and 3.7%-points in the medium and long terms, respectively. In combination with NGCC improvements, this may cause an improvement in the net efficiency, including CO2 capture, from 49% in the short term to 55% and 58% in the medium and long terms, respectively. The total capital costs including capital costs of the NGCC ware calculated to decline from 880 in the short term to 750 and 690 €/kW in the medium and long terms, respectively, with a decline in the incremental capital costs due to capture from 350 in the short term to 270 and 240 €/kW in the medium and long terms, respectively. Finally, the avoidance costs may decline from 45 €/tCO2 in the short term to 33 €/tCO2 in the medium term and 28 €/tCO2 in the long term.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO2) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO2 storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO2 from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO2 capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO2 emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO2, in addition to storing potentially 900–5000 MtCO2 in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO2 emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO2 stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO2 storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO2 storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.

In order to take up the twin challenge of reducing carbon dioxide (CO2) emissions, while meeting a growing energy demand, the potential deployment of carbon dioxide capture and storage (CCS) technologies is attracting a growing interest of policy makers around the world. In this study we evaluate and compare national approaches towards the development of CCS in the United States, Canada, Norway, the Netherlands, and Australia. The analysis is done by applying the functions of innovation systems approach. This approach posits that new technology is developed, demonstrated and deployed in the context of a technological innovation system. The performance assessment of the CCS innovation system shows that the extensive knowledge base and knowledge networks, which have been accumulated over the past years, have not yet been utilized by entrepreneurs to explore the market for integrated CCS concepts linked to power generation. This indicates that the build-up of the innovation system has entered a critical phase that is decisive for a further thriving development of CCS. In order to move the CCS innovation system through this present difficult episode and deploy more advanced CCS concepts at a larger scale; it is necessary to direct policy initiatives at the identified weak system functions, i.e. entrepreneurial activity, market creation and the mobilization of resources. Moreover, in some specific countries it is needed to provide more regulatory guidance and improve the legitimacy for the technology. We discuss how policy makers and technology managers can use these insights to develop a coherent policy strategy that would accelerate the deployment of CCS.

In Part 1, we presented the findings of the EU ACCSEPT project (2006–2007) with regards to scientific, technical, legal and economic issues. In Part 2, we present the analysis of social acceptability on the part of both the lay public and stakeholders. We examine the acceptability of CO2 capture and geological storage (CCS) within the Clean Development Mechanism (CDM) of the Kyoto Protocol. The debate over the inclusion of CCS within the CDM is caught-up in a set of complex debates that are partly technical and partly political and, therefore, difficult, and time-consuming, to resolve. We explore concerns that support for CCS will detract from support for other low-carbon energy sources. We can find no evidence that support for CCS is currently detracting from support for renewable energy sources, though it is probably too early to detect such an effect. Efforts at understanding, engaging with, and communicating to, the lay public and wider stakeholder community (not just business) in Europe are currently weak and inadequate, despite well-meaning statements from governments and industry.

The ACCSEPT project, which ran from January 2006 to December 2007, identified and analysed the main factors which have been influencing the emergence of CO2 capture and geological storage (CCS) within the European Union (EU). The key clusters of factors concern science and technology, law and regulation, economics, and social acceptance. These factors have been analysed through interviews, a large-scale questionnaire conducted in 2006, and discussions in two stakeholder workshops (2006 and 2007). In Part I of this paper, we aim to distil the key messages and findings with regards to scientific, technical, legal and economic issues. There are no compelling scientific, technical, legal, or economic reasons why CCS could not be widely deployed in the forthcoming decades as part of a package of climate change mitigation options. In order to facilitate this deployment, governments at both the EU and Member State levels have an important role to play, in particular in establishing a robust and transparent legal framework (e.g. governing long-term environmental liability) and a strong policy framework providing sufficient and long-term incentives for CCS and CO2 transportation networks.

Public acceptance will be important for the implementation of the geological storage of carbon dioxide (CO2). The purpose of this study is to evaluate how the general public perceives this storage and the factors crucial for its acceptance. Further, this study attempts to analyze and evaluate what kind of information would influence the public acceptance and how. In order to evaluate them, questionnaire surveys concerning the acceptance of CO2 geological storage were conducted among Japanese university students. The questionnaire was designed under the assumption that there were five important factors with regard to the acceptance: risk perception, benefit perception, trust, and two perceptions relating to human interference with the environment (one each for CO2 geological storage and global warming). The questionnaire also investigated the effects of two kinds of information supplied: on natural analogues and on field demonstrations of CO2 storage. The responses were analyzed through confirmatory factor analysis, and the dynamic changes in the perceptions resulting from the supplied information were analyzed. The analysis results include the following: the five factors explained the acceptance very well (>83%), the benefit perception was primarily important for determining public acceptance, and information on the natural analogues decreased the risk perception greatly.

Geologic storage of CO2 can be a viable technology for reducing atmospheric emissions of greenhouse gases only if it can be demonstrated that leakage from proposed storage reservoirs and associated hazards are small or can be mitigated. Risk assessment must evaluate potential leakage scenarios and develop a rational, mechanistic understanding of CO2 behavior during leakage. Flow of CO2 may be subject to positive feedbacks that could amplify leakage risks and hazards, placing a premium on identifying and avoiding adverse conditions and mechanisms. A scenario that is unfavorable in terms of leakage behavior is formation of a secondary CO2 accumulation at shallow depth. This paper develops a detailed numerical simulation model to investigate CO2 discharge from a secondary accumulation, and evaluates the role of different thermodynamic and hydrogeologic conditions. Our simulations demonstrate self-enhancing as well as self-limiting feedbacks. Condensation of gaseous CO2, three-phase flow of aqueous phase–liquid CO2–gaseous CO2, and cooling from Joule–Thomson expansion and boiling of liquid CO2 are found to play important roles in the behavior of a CO2 leakage system. We find no evidence that a subsurface accumulation of CO2 at ambient temperatures could give rise to a high-energy discharge, a so-called “pneumatic eruption”.

Co-injection of sulfur dioxide during geologic carbon sequestration can cause enhanced brine acidification. The magnitude and timescale of this acidification will depend, in part, on the reactions that control acid production and on the extent and rate of SO2 dissolution from the injected CO2 phase. Here, brine pH changes were predicted for three possible SO2 reactions: hydrolysis, oxidation, or disproportionation. Also, three different model scenarios were considered, including models that account for diffusion-limited release of SO2 from the CO2 phase. In order to predict the most extreme acidification potential, mineral buffering reactions were not modeled. Predictions were compared to the case of CO2 alone which would cause a brine pH of 4.6 under typical pressure, temperature, and alkalinity conditions in an injection formation. In the unrealistic model scenario of SO2 phase equilibrium between the CO2 and brine phases, co-injection of 1% SO2 is predicted to lead to a pH close to 1 with SO2 oxidation or disproportionation, and close to 2 with SO2 hydrolysis. For a scenario in which SO2 dissolution is diffusion-limited and SO2 is uniformly distributed in a slowly advecting brine phase, SO2 oxidation would lead to pH values near 2.5 but not until almost 400 years after injection. In this scenario, SO2 hydrolysis would lead to pH values only slightly less than those due to CO2 alone. When SO2 transport is limited by diffusion in both phases, enhanced brine acidification occurs in a zone extending only 5 m proximal to the CO2 plume, and the effect is even less if the only possible reaction is SO2 hydrolysis. In conclusion, the extent to which co-injected SO2 can impact brine acidity is limited by diffusion-limited dissolution from the CO2 phase, and may also be limited by the availability of oxidants to produce sulfuric acid.