International Journal of Greenhouse Gas Control

Published by Elsevier
Print ISSN: 1750-5836
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.
Chemical looping combustion principle 
Arrangement of CLC reactor and auxiliary units of the 120kW CLC pilot rig at Vienna University of Technology 
H2 conversion using ilmenite as oxygen carrier. The experiments are performed at 950°C FR temperature. 
H 2 ( ○ ) and CO ( ● ) conversion using a Ni-based oxygen carrier at 850-900°C. 
CH 4 conversion and CO 2 yield using a Ni-based oxygen carrier. 
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.
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.
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.
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.
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.
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.
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.
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%.
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.
Spider diagram depicting the overall score on the functions of innovation systems by a hundred experts in Norway, Netherlands, United States, Canada and Australia. 
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.
– Impact of investment in CCS upon development of other zero-and low-carbon energy generation options.  
Mean perceptions by stakeholder group of the risk of investment in CCS deterring investment in other low-and zerocarbon technologies (where 1: significant negative impact upon investment, 2: minor negative impact and 3: no impact).
– Perception of the need for economic incentives to support deployment of CCS by NGO respondents (top) and whole sample (bottom).  
– Public perceptions of CCS in selected countries (where 1 indicates 'strongly supportive, 2 'moderately supportive', 3 'on balance, neither positive nor negative', and 4 'moderately opposed').  
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.
With rising levels of atmospheric carbon dioxide (CO2), a portfolio of mitigation options is deemed essential as we transition to a low carbon economy. Carbon dioxide capture and storage (CCS) is one technology that has the potential to mitigate large amounts of CO2 and governments around the world, along with industry and researchers working in the technology space, are excited by this. However, the technology still remains relatively unknown in the minds of most lay citizens and is therefore less well accepted than more traditional forms of power generation. This paper reviews a number of CCS communication research activities that have been undertaken internationally since 2002 and synthesizes them into a logical roadmap of activities. The paper also examines the common strengths and weaknesses of the research activities and makes a number of suggestions for industry representatives and policy makers. The paper also outlines a way to segment stakeholder groups for all communication activities into four target audiences including: influential others; community; education and project specific activities.
This paper presents progress made in CO2 capture by electrothermal swing adsorption (ESA) with activated carbon fibre materials. The current barrier in CO2 capture and storage is the high cost of CO2 separation and capture. CO2 capture by electrothermal swing adsorption can potentially be more energy-effective than conventional temperature swing adsorption (TSA) and pressure swing adsorption (PSA), thus reduces CO2 capture cost. Activated carbon fibre materials have been utilised as the adsorbents due to their demonstrated capabilities for CO2 capture and their good electrical conductivity. This paper reviews the major results in the literature in the development of activated carbon fibre materials and the process of ESA. It also suggests future research directions in CO2 capture by electrothermal swing adsorption.
We report here our study on development of adsorbents suitable for capturing CO2 from synthesis gas (syngas) at high temperatures (>100 °C). Our adsorbents are based on double salts of MgCO3 and K2CO3 in which samples with different ratios of Mg:K were prepared by the wet mixing method of magnesium nitrate and potassium carbonate. The adsorbents were characterized by X-ray diffraction analysis, thermogravimetric analysis (TGA), and N2 adsorption and desorption at 77 K. The morphology of the samples was observed with scanning electron microscopy (SEM). CO2 adsorption experiments were performed at four temperatures, 300 °C, 350 °C, 375 °C, and 400 °C, which correspond to the operating temperature range of gases exiting a typical water gas shift reactor and entering a gas turbine in the Integrated Gasification Combined Cycle (IGCC) process. The CO2 adsorption amounts were 1.65 wt%, 8.47 wt%, 8.55 wt%, and 0.63 wt% respectively at a CO2 partial pressure of 100 kPa. These adsorbents also exhibited excellent cycling stability both in temperature swing adsorption and pressure swing adsorption operation. The kinetics of CO2 adsorption at different temperatures was obtained by using the linear driving force (LDF) model and a diffusion activation barrier of 21 kJ/mol was also inferred.Graphical abstractHighlights► Successful synthesis of adsorbents for CO2 capture at high temperatures. ► Excellent cycling stability in temperature/pressure swing. ► Kinetics of CO2 adsorption at different temperatures obtained with LDF model.
Coalbed methane is an important resource of energy. Meanwhile CO2 sequestration in coal is a potential management option for greenhouse gas emissions. An attractive aspect to this process is that CO2 is adsorbed to the coal, reducing the risk of CO2 migration to the surface. Another aspect to this is that the injected CO2 could displace adsorbed methane leading to enhanced coalbed methane recovery. Therefore, in order to understand gas migration within the reservoir, mixed-gas adsorption models are required. Moreover, coal reservoir permeability will be significantly affected by adsorption-induced coal swelling during CO2 injection. Coal swelling is directly related to reservoir pressure and gas content which is calculated by adsorption models in reservoir simulation. Various models have been studied to describe the pure- and mixed-gas adsorption on coal. Nevertheless, only the Langmuir and Extended Langmuir models are usually applied in coal reservoir simulations. This paper presents simulation work using several approaches to representing gas adsorption, implemented into the coal seam gas reservoir simulator SIMED II. The adsorption models are the Extended Langmuir model (ELM), the Ideal Adsorbed Solution (IAS) model and the Two-Dimensional Equation of State (2D EOS). The simulations based on one Australian and one American coal sample demonstrated that (1) the Ideal Adsorbed Solution model, in conjunction with Langmuir model as single-component isotherm, shows similar simulation results as the ELM for both coals, with the IAS model representing the experimental adsorption data more accurately than the ELM for one coal and identically with the ELM for the other coal; (2) simulation results using the 2D EOS, however, are significantly different to the ELM or IAS model for both coal samples. The magnitude of the difference is also dependent on coal swelling and the well operating conditions, such as injection pressure.
This review presents a summary of the main interactions that occur during the carbon dioxide (CO2) adsorption at the surface of steel slags with basic (CaO, MgO), amphoteric (Al2O3, Cr2O3, TiO2, MnO, iron oxides) and acidic (SiO2) oxides. The high content of metal oxides in steel slags gives them a great potential to adsorb CO2, reaching a saturation value of about 0.25 kg of CO2/kg of slag. CO2 is physisorbed and chemisorbed on the most of metal oxide types. Generally, the CO2 physisorption on the basic and amphoteric metal oxides involves an electrostatic interaction between the CO2 and the cation from the oxides while the CO2 chemisorption rather implicates the basic sites that acts as the electron donor, and which are associated with O2− ions localized at surface defects. These interactions result in the formation of carbonates (monodentates or unidentates and bidentates). The affinity of oxides for the CO2 and the carbonate formation principally depend of the strength and number of basic sites at their surface and varies as following: basic oxides > amphoteric oxides > acidic oxides. The basic metal oxides generally represent the best electron donors and thus the best CO2 adsorbents due to the high basicity and their great number of reaction sites. Hence, it appears that the surface structure of basic and amphoteric metal oxides which may favour their interaction with the CO2, as well as their basicity is the determinant factor contributing to the formation of carbonate species. The molecular analysis of CO2 adsorption on steel slag metal oxides will provide useful data to identify rate-controlling mechanisms and should be considered for the development of new effective methods for the capture of atmospheric CO2 emissions released from industries.
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.
This paper explores how the widely held public policy view of the evolution of the risk profile associated with geologic carbon dioxide (CO2) storage profoundly influences the public policy dialogue about how to best address the long-term risk profile for geologic storage. Evidence emerging from research and pilot scale field demonstrations of CO2 storage demonstrates that, with proper site characterization and sound operating practices, retention of stored CO2 will increase with time thus invalidating the premise of an ever growing risk. The authors focus on key issues of fit, interplay, and scalability associated with the ability of a trust fund funded by a hypothetical $1 per tonCO2 tipping fee for each ton of CO2 stored in the United States under WRE450 and WRE550 climate policies to manage such risks in an economically efficient and environmentally effective manner. The authors conclude there is no intrinsic value – in terms of risk management or risk reduction – in creating a trust fund predicated solely on collecting a universally applied tipping fee that does not take into account site-specific risk profiles. If left to grow unchecked, a trust fund that is predicated on a constant stream of payments unrelated to each contributing site's risk profile could result in the accumulation of hundreds of billions to more than a trillion dollars contributing to significant opportunity cost of capital. Further, rather than mitigating the financial consequences of long-term CCS risks, this analysis suggests a blanket $1 per tonCO2 tipping fee, if combined with a concomitant limitation of liability may increase the probability and frequency of long-term risk by eliminating financial incentives for sound operating behavior and site selection criteria—contribute to moral hazard. At a minimum, effective use of a trust fund requires: (1) strong oversight regarding site selection and fund management, and (2) a clear process by which the fund is periodically valued and funds collected are mapped to the risk profile of the pool of covered CCS sites. Without appropriate checks and balances, there is no a priori reason to believe that the amount of funds held in trust will map to the actual amount of funds needed to address long-term care expenses and delimited compensatory damages. For this reason, the authors conclude that financing a trust fund or other risk management instrument should be based on a site delimited estimate of potential future expected financial consequences rather than on the random adoption of a fixed funding stream, e.g., a blanket $1 per ton, because it “sounds” reasonable.
The aim of this study was to develop and apply an advanced, measurement based method for the estimation of annual CH4 and N2O emissions and thus gain improved understanding on the actual greenhouse gas (GHG) balances of combustion of fossil fuels, peat, biofuels and REF. CH4 and N2O emissions depend strongly on combustion conditions, and therefore the emission factors used in the calculation of annual emissions contain significant uncertainties. Fluidised bed combustion (FBC) has many good properties for combustion of different types of fuels and fuels of varying quality, e.g., biofuels and wastes. Therefore, it is currently increasing its market share. In this study, long term measurements (up to 50 days) were carried out at seven FBC boilers representing different size classes, loadings and fuel mixes. Both decreasing load and increasing share of coal in fuel mix increased N2O emissions. Measurement results from different loading levels were combined with the common loading curves of similar plants in Finland to estimate annual emissions. Based on the results, recommendations for emission factors for the Finnish GHG emission inventory are given. The role of FBC as a potential technology for the utilisation of biofuels and wastes with future GHG reduction requirements is discussed.
-Block diagrams illustrating post-combustion, pre-combustion, and oxy-combustion systems.
-Schematic of the Carbozyme permeation process.
-Performance of polymer membrane developed by LANL.
There is growing concern that anthropogenic carbon dioxide (CO2) emissions are contributing to global climate change. Therefore, it is critical to develop technologies to mitigate this problem. One very promising approach to reducing CO2 emissions is CO2 capture at a power plant, transport to an injection site, and sequestration for long-term storage in any of a variety of suitable geologic formations. However, if the promise of this approach is to come to fruition, capture costs will have to be reduced. The Department of Energy's Carbon Sequestration Program is actively pursuing this goal. CO2 capture from coal-derived power generation can be achieved by various approaches: post-combustion capture, pre-combustion capture, and oxy-combustion. All three of these pathways are under investigation, some at an early stage of development. A wide variety of separation techniques is being pursued, including gas phase separation, absorption into a liquid, and adsorption on a solid, as well as hybrid processes, such as adsorption/membrane systems. Current efforts cover not only improvements to state-of-the-art technologies but also development of several innovative concepts, such as metal organic frameworks, ionic liquids, and enzyme-based systems. This paper discusses the current status of the development of CO2 capture technology.
To reduce the risks of climate change, atmospheric concentrations of greenhouse gases must be lowered. Direct capture of CO2 from ambient air, “air capture”, might be one of the few methods capable of systematically managing dispersed emissions. The most commonly proposed method for air capture is a wet scrubbing technique which absorbs CO2 in an alkaline absorbent, i.e. sodium hydroxide producing an aqueous solution of sodium hydroxide and sodium carbonate. In most of the previous works it was assumed that the absorbent would be regenerated and CO2 liberated from the alkaline carbonate solution using a lime and calcium carbonate causticization cycle.We describe a novel technique for recovering sodium hydroxide from an aqueous alkaline solution of sodium carbonate and present an end-to-end energy and exergy analysis. In the first step of the recovery process, anhydrous sodium carbonate is separated from the concentrated sodium hydroxide solution using a two-step precipitation and crystallization process. The anhydrous sodium carbonate is then causticized using sodium tri-titanate. The titanate direct causticization process has been of interest for the pulp and paper industry and has been tested at lab- and pilot-scale. In the causticization process, sodium hydroxide is regenerated and carbon dioxide is liberated as a pure stream, which is compressed for use or disposal. The technique requires ∼50% less high-grade heat than conventional causticization and the maximum temperature required is reduced by at least 50 °C. This titanate cycle may allow a substantial reduction in the overall cost of direct air capture.
Alberta is the province with the largest CO2 emissions in Canada, with approximately two-thirds of emissions originating from large stationary sources. Due to the fortuitous association of large CO2 sources with the storage capacity offered by the underlying Alberta basin, it is expected that large-scale CO2 geological storage in Canada will occur in Alberta first, and both levels of governments are contemplating measures to facilitate implementation. A review of the current provincial and federal legislation and regulations presented in this paper indicates that the existing legal and regulatory regime is reasonably sufficient, with some modifications, to accommodate the active injection phase of CO2 capture and storage (CCS) operations, and the early takers of this new technology. However, governments in Alberta and Canada, and likely everywhere, need to address several pressing issues dealing mainly with the CCS post-operational phase. These issues, reviewed in this paper from an Alberta and Canadian perspective, fall into several categories: jurisdictional, property (ownership), regulatory and liability. Because Alberta is a landlocked province, matters relating to CO2 storage under the seabed will not be addressed here except when discussing matters of jurisdiction and CO2 classification. Possible models for post-injection liability transfer to the state are also presented. Although this review is focused on western Canada conditions, the issues are broad enough to be of interest in other jurisdictions, which may also adopt parts of the legal and regulatory framework that is quite well developed in Alberta.
In developing country like India, most of the vapor compression based refrigeration, air conditioning and heat pump systems continue to run on halogenated refrigerants due to its excellent thermodynamic and thermo-physical properties apart from the low cost. However, the halogenated refrigerants have adverse environmental impacts such as ozone depletion potential (ODP) and global warming potential (GWP). Hence, it is necessary to look for alternative refrigerants to full fill the objectives of the international protocols (Montreal and Kyoto) and to satisfy the growing worldwide demand. This paper reviews the various experimental and theoretical studies carried out around the globe with environment friendly alternatives such as hydrocarbons (HC), hydroflurocarbons (HFC) and their mixtures, which are going to be the promising long-term alternatives. In addition, the technical difficulties of mixed refrigerants and future challenges of the alternatives are discussed. The problems pertaining to the usage of environment friendly refrigerants are also analyzed.
Amine volatility is a key screening criterion for amines to be used in CO2 capture. Excessive volatility may result in significant economic losses and environmental impact. It also dictates the capital cost of the water wash. This paper reports measured amine volatility in 7 m MEA (monoethanolamine), 8 m PZ (piperazine), 7 m MDEA (n-methyldiethanolamine)/2 m PZ (piperazine), 12 m EDA (ethylenediamine), and 5 m AMP (2-amino-2-methyl-1-propanol) at 40–60 °C with lean and rich loadings giving CO2 partial pressures of 0.5 and 5 kPa at 40 °C. The amine concentrations were chosen to maximize CO2 capture capacity at acceptable viscosity. At the lean loading condition (where volatility is of greatest interest), the amines are ranked in order of increasing volatility: 7 m MDEA/2 m PZ (6/2 ppm), 8 m PZ (8 ppm), 12 m EDA (9 ppm), 7 m MEA (31 ppm), and 5 m AMP (112 ppm). The apparent amine partial molar excess enthalpies in these systems were estimated to range from ∼10 to 87 kJ/mol of amine.
The use of amines for CO2 capture from flue gases involves one distinct difference and challenge from traditional amine acid gas capture: the presence of dioxygen and its role in the oxidative degradation of the amine. Insights on mechanisms of degradation in flue gas CO2 capture can be obtained from observations of other gas treating processes – primarily trace O2 contamination in “traditional” gas treating amine units as well as the autoxidation of amino acids during oxidative dehydrosulfurization using iron chelates. Three distinct pathways for degradation initiation have been identified: thermal, autoxidation (reaction involving dioxygen) and direct reactions with CO2. This paper will focus on the dioxygen pathway and insights that have been gained from observations of other gas treating processes – primarily trace O2 contamination in “traditional” gas treating amine units as well as the autoxidation of amino acids during oxidative dehydrosulfurization using iron chelates.
The capture of carbon dioxide (CO2) from a simulated flue gas stream was achieved by utilizing immobilized tertiary amine solid sorbents. The tertiary amine immobilized in these solid substrates was 1, 8 Diazabicyclo-[5.4.0]-undec-7-ene (DBU) and it has the stoichiometric capability of capturing carbon dioxide at a 1:1 R-NH2:CO2 molar ratio. This is a unique feature compared to other primary and secondary amines which capture CO2 at a 2:1 molar ratio, thus making the immobilized DBU solid sorbents competitive with existing commercially available sorbents and liquid amine-based capture systems. The immobilized DBU solid sorbents prepared in this study exhibit acceptable CO2 capture capacities of 3.0 mol CO2/kg sorbent at 298 K; however, at the critical operational temperature of 338 K, the capacity was reduced to 2.3 mol/kg sorbent. The DBU sorbents did exhibit acceptable stability over the adsorption/desorption temperature range of 298–360 K based on XPS and TGA analyses.
Absorption by chemical solvents combined with CO2 long-term storage appears to offer interesting and commercial applicable CO2 capture technology. However one of the main disadvantages is related to the large quantities of heat required to regenerate the amine solvent that means an important power plant efficiency penalty. Different studies have analyzed alternatives to reduce the heat duty on the reboiler and the thermal integration requirements on existing power cycles. In these studies integration principles have been well set up, but there is a lack of information about how to achieve an integrated design and the thermal balances of the modified cycle flowsheet. This paper proposes and provides details about a set of modifications of a supercritical steam cycle to overcome the energy requirements through energetic integration with the aim of reducing the efficiency and power output penalty associated with CO2 capture process. Modifications include a new designed low-pressure heater flowsheet to take advantage of the CO2 compression cooling for postcombustion systems and integration of amine reboiler into a steam cycle. It has been carried out several simulations in order to obtain power plant performance depending on sorbent regeneration requirements.
This work provides the essential information and approaches for integration of carbon dioxide (CO2) capture units into power plants, particularly the supercritical type, so that energy utilization and CO2 emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO2 capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO2 captured and avoided. The parameters of interest include CO2 capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO2 capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO2 capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO2 at a higher efficiency to achieve greater CO2 emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO2 capture unit should be considered for process integration.
There is strong world-wide interest in developing new and improved processes for post-combustion capture of CO2, often using chemical absorption. Developers of new processes make positive claims for their proposals in terms of low energy consumption, but these are usually difficult to validate. This paper demonstrates that rigorous application of thermodynamic analysis and process simulation provides a powerful way to quantitatively estimate the energy requirements of CO2-capture processes by applying the methodology to the analysis and evaluation of the chilled-ammonia process.
The chilled ammonia process absorbs the CO2 at low temperature (2–10 ∘C). The heat of absorption of carbon dioxide by ammonia is significantly lower than for amines. In addition, degradation problems can be avoided and a high carbon dioxide capacity is achieved. Hence, this process shows good perspectives for decreasing the energy requirement. However, a scientific understanding of the processes is required. The properties of the NH3- CO2- H2O system were described using the Extended UNIQUAC electrolyte model developed by Thomsen and Rasmussen in a temperature range from 0 to 110 ∘C and pressure up to 100 bars [1]. The results show that solid phases consisting of ammonium carbonate and bicarbonate are formed in the absorber. The energy requirements in the absorber and in the desorber have been studied. The enthalpy calculations show that an energy requirement for the desorber lower than 2 GJ/ton CO2 can be reached.
Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO2 that was introduced from deep magmatic sources via faults and replaced pre-existing CH4. In some respects this process is analogous to sequestration of anthropogenic CO2. Laboratory studies indicate that CO2:CH4 storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO2 by a factor of up to 1.5.Present-day distribution of CO2 in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P–T conditions, most of the CO2 occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO2 occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO2 solubility. The CO2 has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO2 sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P–T conditions.In situ CO2 contents of Sydney Basin coals range up to 20 m3/t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO2 stored do not exceed ∼60% of the total CO2 storage capacity. Therefore, the maximum CO2 saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.
The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO2. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues.At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods.In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO2 toward surface. This study also provides information on the origin of CO2, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story.The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO2. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state.These two complementary studies proved the interest of geochemical monitoring to survey the CO2 behaviour, and gave information on its use.
Mathematical tools are needed to screen out sites where Joule–Thomson cooling is a prohibitive factor for CO2 geo-sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO2 injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kg s−1 (0.1 MT yr−1) into moderately warm (>40 °C) and permeable formations (>10−14 m2 (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as 2 MPa (290 psi).
A carbon budget was calculated for Tompkins County, NY, a semi-rural upstate county with a population density of 78 pp/km2. The costs and potential for several carbon mitigation options were analyzed in four categories: terrestrial C sequestration, local power generation, transportation, and energy end-use efficiency. This study outlines a methodology for conducting this type of local-scale analysis, including sources and calculations adaptable to different localities. Effective carbon mitigation strategies for this county based on costs/Mg C and maximum potential include reforestation of abandoned agricultural lands, biomass production for residential heating and co-firing in coal power plants, changes in personal behavior related to transportation (e.g., public transportation), installation of residential energy efficient products such as programmable thermostats or compact fluorescent light bulbs, and development of local wind power. The total county emissions are about 340 Gg C/year, with biomass sequestration rates of 121 Gg C/year. The potential for mitigation, assuming full market penetration, amounts to about 234 Gg C/year (69%), with 100 Gg C/year (29%) at no net cost to the consumer. The development of local-scale C mitigation plans based on this sort of model of analysis is feasible and would be useful for guiding investments in climate change prevention.
Carbon capture and storage (CCS) may play a central role in managing carbon emissions from the power sector and industry, but public support for the technology is unclear. To address this knowledge gap, and to test the use of discrete choice analysis for determining public attitudes, two focus groups and a national survey were conducted in Canada to investigate the public's perceptions of the benefits and risks of CCS, the likely determinants of public opinion, and overall support for the use of CCS.The results showed slight support for CCS development in Canada, and a belief that CCS is less risky than normal oil and gas industry operations, nuclear power, or coal-burning power plants. A majority of respondents indicate that they would support the use of CCS as part of a greenhouse gas reduction strategy, although it would likely have to be used in combination with energy efficiency and alternative energy technologies in order to retain public support.
A laboratory-scale reactor system is built and operated to measure the kinetic of formation for single and mixed carbon dioxide–tetrahydrofuran hydrates. The T-cycle method, which is used to collect the kinetic data, is briefly discussed. For single carbon dioxide hydrate, the induction time decreases with the increase of the initial carbon dioxide pressure up to 2.96 MPa. Beyond this pressure, the induction time is becoming relatively constant with the increase of initial carbon dioxide pressure indicating that the liquid phase is completely supersaturated with carbon dioxide. Experimental results show that the inclusion of tetrahydrofuran reduces the induction time required for hydrate formation. These observations indicate hydrate nucleation process and onset growth are more readily to occur in the presence of tetrahydrofuran. In contrast, the presence of sodium chloride prolongs the induction time due to clustering of water molecules with the ions and the salting-out effects. It is also shown that the degree of subcooling required for hydrate formation is affected by the presence of tetrahydrofuran and sodium chloride in the hydrate forming system. The presence of tetrahydrofuran in the hydrate system significantly reduces the amount of carbon dioxide uptake. The apparent rate constant, k, for those systems are reported.
Top-cited authors
Anders Lyngfelt
  • Chalmers University of Technology
Stefan Bachu
José Figueroa
  • U.S. Department of Energy
P. H. M. Feron
  • The Commonwealth Scientific and Industrial Research Organisation
S.I Plasynski
  • National Energy Technology Laboratory