Search

In this paper an approach for analysing the potential for implementation of different technology pathways for the European pulp and paper industry (PPI) is presented. The approach is based on detailed technical research and aggregates the knowledge from previous studies to incorporate the whole European PPI. Thus, the potential for different technology pathways can be estimated on a European level whilst still considering important characteristics of individual mills. The usefulness of the approach was exemplified by applying it to a case study of the potential for introduction of carbon capture and storage (CCS) within the European PPI. The results from the case study show that for the European PPI, CCS has an up-hill road in order to be a viable, large scale alternative for reduction of CO2 emissions. If CCS is to be introduced in large scale within the European PPI, large biomass-based point sources of CO2 emissions need to be included when planning for CCS infrastructure and also the infrastructure needs to be built out for clusters emitting <20 MtCO2/yr. [ABSTRACT FROM AUTHOR]

This paper investigates various alternatives for the application of CCS at a cement plant which is one of the focus site for CCS deployment in Norway. A matrix consisting of nine CCS alternative chains is analysed in order to quantify cost reduction potentials across the CCS value chain based on an in-house techno-economic assessment methodology and tool called iCCS. In particular, the paper quantifies the strong cost reduction potential of second generation capture technologies and transport technology selection. CO 2 EOR is also identified to have a strong potential to reduce the overall CCS cost, however the cost benefits are strongly dependent on the oil value and the considered EOR injection period. The impact of the inclusion of CO 2 capture and conditioning in the cost of cement shows that public financial support will be required to ensure that the plant remain competitive under current cement market price. Finally, comparison of the full-scale capture versus part-scale capture shows, in this case, that the economies of scale are nearly compensated by the additional steam cost, therefore limiting the interest for full-scale implementation. However, joint deployment with the two other CCS potential sites in Norway (Yara and Klemenstrud) may bring more synergies. [ABSTRACT FROM AUTHOR]

• A novel decarbonization concept applied to offshore natural gas wells benefiting CCUS technology. • A comprehensive CFD model considers real gas EOS and the behaviours of gas, droplets, liquid film. • Compatible with pure CO 2 and CH 4 -CO 2 models to study condensation and separation characteristics. • The maximum CO 2 condensation amount under high pressure and low temperature is 10.33 ton/h. • The maximum CO 2 capture capacity is 4.43 ton/h with high heterogeneous droplet mass concentration. Carbon capture, utilisation and storage (CCUS) is of unique significance for building a green and resilient energy system, and it is also a key solution to tackle the climate challenge. The concept of supersonic decarburization, a joint product of non-equilibrium condensation and swirling separation, can contribute to CCUS technology in a clean way. In this paper, a numerical model is established and validated to investigate the complex physical phenomena of supersonic decarbonization in a high-pressure environment based on the real gas equation of state. The model is compatible with the pure CO 2 model and CH 4 -CO 2 model. Through the simulation of the supersonic nozzle and supersonic separator, the condensation and separation performance of supersonic decarbonization technology was evaluated. For the condensation performance of carbon dioxide, the results show that higher pressure makes it much easier to achieve the condensation process. When the pressure is supercritical, the decrease of inlet temperature or the increase of inlet mole fraction of CO 2 leads to a higher liquid fraction. For separation performance, when the mass concentration of inlet heterogeneous droplets increases from 0.1 kg/m3 to 7.5 kg/m3, the carbon separation amount increases from 3.33 ton/h to 4.43 ton/h, while the exergy loss of condensed CO 2 drops from 436.57 kJ/kg to 329.56 kJ/kg. It demonstrates that the decarburization process is easier, and exergy required for condensation decreases when the concentration of the foreign core is larger. This new concept is beneficial to CCUS technology and can be applied to carbon capture in offshore natural gas processing. [ABSTRACT FROM AUTHOR]

Partition (or distribution) coefficients determine the relative equilibrium concentrations of chemical constituents (or chemical tracers) in each of the phases of a multi-phase system under dilute conditions. The various fluid phases in a reservoir have differing transport properties (e.g. varying relative permeability) and to correctly interpret the behaviour of injected chemical tracers it is essential that accurate partition coefficients are known. In the context of carbon geosequestration or long-term storage of CO 2 , chemical tracers will be predominantly exposed to an environment consisting of supercritical CO 2 and formation water as the main fluid phases. To estimate/simulate the reservoir properties relevant to injected CO 2 tagged with chemical tracers, it is therefore necessary to incorporate high pressure/temperature CO 2 /water partition coefficients into any model/simulation. In this paper, we present a method to determine these partition coefficients for gaseous chemical tracers using a variation of the widely used EPICS (or equilibrium partitioning in a closed system) method. With this method, only the concentration in one phase (in this case, CO 2 ) needs to be measured. We then report these values for a series of representative chemical tracers (i.e. krypton, xenon, sulfur hexafluoride, perdeuterated methane and R134a) at pressure/temperature conditions that have been previously used at the CO2CRC's Otway CCS demonstration project in Victoria, Australia. These values were generally lower than the corresponding Henry's Law coefficients at comparable temperatures. Experiments also examined the impact of adding CH 4 to the system to mimic feedstock gas at the CO2CRC Otway project and provide data pertinent to scenarios where CO 2 is injected into depleted CH 4 gas fields. These values are compared with Henry's Law coefficients and another recently published set of high pressure/temperature partition coefficients. With computational simulations, we have shown that these differences are potentially significant and demonstrate their impact in three typical CO 2 geo-sequestration scenarios (i.e. injection into two types of aquifers and injection into a depleted reservoir with a gas cap). [ABSTRACT FROM AUTHOR]

In the present paper, a CO 2 cryogenic capture for flue gas of an LNG-fired power generation system is proposed, in which LNG cold energy can be fully utilized during the gasification process. First of all, the flue gas is compressed to facilitate the CO 2 solid formation and separation. Sequentially, the CO 2 -removed flue gas expands to supply most of the cold energy needed for the cryogenic process. In comparison with traditional CO 2 -capture systems in LNG-fired power generation cycle, the new system does not require gasifying excessive amount of LNG. Based on the HYSYS simulation, the CO 2 capture pressure and temperature are investigated as the key parameters to find the appropriate working conditions of the CO 2 -capture system. The results show that the system can achieve a 90% CO 2 recovery rate or higher if the flue gas temperature can be lowered to less than −140 °C. [ABSTRACT FROM AUTHOR]

Bioenergy with carbon capture and storage (BECCS) can sequester atmospheric CO2, while producing electricity. The CO2 avoidance cost (CAC) is used to calculate the marginal cost of avoided CO2 emissions for BECCS as compared to other established energy technologies. A comparative analysis using four different reference-case power plants for CAC calculations is performed here to evaluate the CO2 avoidance cost of BECCS implementation. Results from this work demonstrate that BECCS can generate electricity at costs competitive with other neutral emissions technologies, while simultaneously removing CO2 from the atmosphere. Approximately 73% of current coal power plants are approaching retirement by the year 2035 in the U.S. After considering CO2 sequestered from the atmosphere and coal power plant CO2 emissions displaced by BECCS, CO2 emissions can be reduced by 1.4 billion tonnes per year in the U.S. alone at a cost of $88 to $116 per tonne of CO2 removed from the atmosphere, for 10% to 90% of available biomass used, respectively. CAC calculations in this paper indicate that BECCS can help the U.S. and other countries transition to a decarbonized electricity grid, as simulations presented in this paper predict that BECCS power plants operate at lower CACs than coal plants with CCS. [ABSTRACT FROM AUTHOR]

Adsorption is considered as one of the most promising technologies for CCS. Gas adsorption involves the separation of gaseous components from flue gas using solid adsorbents. The gaseous component, adsorbate, is adsorbed from the gas phase on a solid material. Regarding CO2 adsorption, it is important to consider the parameters, that is the high sorption capacity, CO2 selectivity, regeneration and stability in multiple cycles. New directions for the development of adsorbents are focused on increasing their capacity ' for this purpose, amine impregnation is carried out. This paper presents a new approach to obtaining mesoporous material from fly ash and, based on this, a new physico-chemical adsorbent obtained by impregnation. The effectiveness of the process was confirmed by thermogravimetric analysis and FTIR infrared spectroscopy. [ABSTRACT FROM AUTHOR]

In this paper, the methods of the integration of a supercritical coal-fired power plant with membrane CCS installation are shown. In addition to membrane modules, the CCS installation also consists of two vacuum pumps and two CO2 compressors. In this paper, the relationship between the auxiliary power required to drive these machines and the recoverable amount of heat is shown. This relationship is the reason for the integration of the supercritical coal unit with the CCS installation, which is used for cooling compressed CO2 in the CCS installation by use of condensate (or feed water) from the supercritical coal unit cycle. This cooling process causes both a reduction of the auxiliary power required to drive the compressors and vacuum pumps and increase of power ratio of a steam turbine. In this paper, the optimisation method for minimising the decrease of overall efficiency of the power plant connected with its integration with CCS installation is shown. This results in choosing the optimal pressure ratios in the applied compressors and vacuum pumps under the condition of sufficient heat transmission to the steam turbine cycle. For investigated units, the cost of CO2 emission avoidance and the break-even price of electricity were also calculated. [Copyright &y& Elsevier]

Integrated gasification combined cycle systems (IGCC) are becoming more popular because of the characteristics, by which they are characterized, including low pollutants emissions, relatively high efficiency of electricity production and the ability to integrate the installation of carbon capture and storage (CCS). Currently, the most frequently used CO2 capture technology in IGCC systems is based on the absorption process. This method causes a significant increase of the internal load and decreases the efficiency of the entire system. It is therefore necessary to look for new methods of carbon dioxide capture. The authors of the present paper propose the use of membrane separation. The paper reviews available membranes for use in IGCC systems, indicates, inter alia, possible places of their implementation in the system and the required operation parameters. Attention is drawn to the most important parameters of membranes (among other selectivity and permeability) influencing the cost and performance of the whole installation. Numerical model of a membrane was used, among others, to analyze the influence of the basic parameters of the selected membranes on the purity and recovery ratio of the obtained permeate, as well as to determine the energetic cost of the use of membranes for the CO2 separation in IGCC systems. The calculations were made within the environment of the commercial package Aspen Plus. For the calculations both, membranes selective for carbon dioxide and membranes selective for hydrogen were used. Properly selected pressure before and after membrane module allowed for minimization of energy input on CCS installation assuring high purity and recovery ratio of separated gas. [ABSTRACT FROM AUTHOR]

Meeting the Paris Agreement will most likely require the combination of CO 2 capture and biomass in the industrial sector, resulting in net negative emissions. CO 2 capture within the industry has been extensively investigated. However, biomass options have been poorly explored, with literature alluding to technical and economic barriers. In addition, a lack of consistency among studies makes comparing the performance of CO 2 capture and/or biomass use between studies and sectors difficult. These inconsistencies include differences in methodology, system boundaries, level of integration, costs, greenhouse gas intensity of feedstock and energy carriers, and capital cost estimations. Therefore, an integrated evaluation of the techno-economic performance regarding CO 2 capture and biomass use was performed for five energy-intensive industrial sub-sectors. Harmonization results indicate that CO 2 mitigation potentials vary for each sub-sector, resulting in reductions of 1.4–2.7 t CO 2 /t steel (77%–149%), 0.7 t CO 2 /t cement (92%), 0.2 t CO 2 /t crude oil (68%), 1.9 t CO 2 /t pulp (1663%–2548%), and 34.9 t CO 2 /t H 2 (313%). Negative emissions can be reached in the steel, paper and H 2 sectors. Novel bio-based production routes might enable net negative emissions in the cement and (petro)chemical sectors as well. All the above-mentioned potentials can be reached for 100 €/t CO 2 or less. Implementing mitigation options could reduce industrial CO 2 emissions by 10 Gt CO 2 /y by 2050, easily meeting the targets of the 2 °C scenario by the International Energy Agency (1.8 Gt CO 2 /y reduction) for the industrial sector and even the Beyond 2 °C scenario (4.2 Gt CO 2 /y reduction). • Literature review on CO 2 mitigation in steel, cement, chemical, H 2 and paper sectors. • Introduction harmonized methodology to allow comparison between industrial sectors. • All investigated sectors have large reduction potentials for <100 €/t CO 2 avoided. • Negative emissions possible in iron/steel, H 2 and paper sectors. • Potential CO 2 emission reduction of 10 Gt/yr in 2050, easily meeting climate target. [ABSTRACT FROM AUTHOR]

Carbon capture and storage technology has the potential to reduce anthropogenic CO 2 emissions. However, the geomechanical response of the reservoir and sealing caprocks must be modelled and monitored to ensure that injected CO 2 is safely stored. To ensure confidence in model results, there is a clear need to develop ways of comparing model predictions with observations from the field. In this paper we develop an approach to simulate microseismic activity induced by injection, which allows us to compare geomechanical model predictions with observed microseismic activity. We apply this method to the In Salah CCS project, Algeria. A geomechanical reconstruction is used to simulate the locations, orientations and sizes of pre-existing fractures in the In Salah reservoir. The initial stress conditions, in combination with a history matched reservoir flow model, are used to determine when and where these fractures exceed Mohr–Coulomb limits, triggering failure. The sizes and orientations of fractures, and the stress conditions thereon, are used to determine the resulting micro-earthquake focal mechanisms and magnitudes. We compare our simulated event population with observations made at In Salah, finding good agreement between model and observations in terms of event locations, rates of seismicity, and event magnitudes. [ABSTRACT FROM AUTHOR]

For large volumes of carbon dioxide (CO 2 ) onshore and offshore transportation, pipeline is considered the preferred method. This paper presents a study of the pipeline network planned in the Humber region of the UK. Steady state process simulation models of the CO 2 transport pipeline network were developed using Aspen HYSYS®. The simulation models were integrated with Aspen Process Economic Analyser® (APEA). In this study, techno-economic evaluations for different options were conducted for the CO 2 compression train and the trunk pipelines respectively. The evaluation results were compared with other published cost models. Optimal options of compression train and trunk pipelines were applied to form an optimal case. The overall cost of CO 2 transport pipeline network was analyzed and compared between the base case and the optimal case. The results show the optimal case has an annual saving of 22.7 M€. For the optimal case, levelized energy and utilities cost is 7.62 €/t-CO 2 , levelized capital cost of trunk pipeline is about 8.11 €/t-CO 2 and levelized capital cost of collecting system is 2.62 €/t- CO 2 . The overall levelized cost of the optimal case was also compared to the result of another project to gain more insights for CO 2 pipeline network design. [ABSTRACT FROM AUTHOR]

Mineralna karbonatyzacja jest jedną z metod ograniczania antropogenicznej emisji CO2. Metoda ta polega na wykorzystaniu naturalnego zjawiska wiązania ditlenku wêgla przez surowce naturalne lub beton. Od pojawienia siê w 1990 r. w NATURE pierwszej publikacji dotyczącej mineralnej sekwestracji CO2, prowadzone są badania nad wykorzystaniem zjawiska wiązania ditlenku wêgla. W wyniku procesu ditlenek wêgla wiązany jest w stałej formie, co powoduje, że metoda ta jest bezpieczna ekologicznie. Dodatkowo w wyniku reakcji, która jest egzotermiczna, uwalnia siê ciepło, które może byæ potencjalnie wykorzystane. Proces ten może byæ stosowany jako ostatni etap tech-nologii CCS (Carbon Capture and Storage). Mineralna karbonatyzacja może byæ realizowana jako metoda in-situ i ex-situ. Mineralna sekwestracja proponowana jest i badana zarówno dla surowców mineralnych, jak i odpadów. W Polsce szczególnie interesującą opcją jest zastosowanie do wiązania CO2 na drodze mineralnej karbonatyzacji odpadów energetycznych o wysokiej zawartości CaO i ograniczonym wykorzystaniu gospodarczym. Do wiązania CO2 przeanalizowano oprócz odpadów energetycznych również żużle hutnicze i pyły z pieców cementowych. Drugą opcją prowadzenia mineralnej karbonatyzacji jest stosowanie surowców naturalnych. Do mineralnej sekwestracji CO2 mogąbyæ potencjalnie stosowane minerały, takie jak: oliwin, serpentyn czy talk. W artykule przed-stawiono możliwości zastosowania surowców mineralnych do obniżenia emisji ditlenku wêgla. Przeanalizowano również surowce mineralne wystêpując w Polsce, które potencjalnie mogą byæ stosowane do sekwestracji CO2 w ramach procesu ex situ i in situ. Artykuł jest wstêpną analizą możliwości wykorzystania tego typu surowców do wiązania CO2 w Polsce. Mineral carbonation is one possible approach to reducing anthropogenic CO2 emissions. This method involves the use of a natural phenomenon of carbon dioxide causing CO2 to bond with natural or concrete materials. Since the appearance of the first publication on the mineral sequestration of CO2 (in 1990 in Nature), research has been conducted into making use of the carbon dioxide bond. The objective was to bind carbon dioxide into a solid form, a method rendering it environmentally safe. In addition, as a result of the reaction being exothermic, heat is released which can potentially be used. This process may be employed as the last step of CCS (Carbon Capture and Storage). Mineral carbonation can be implemented as a method both in situ and ex situ. Mineral sequestration is proposed and has been tested for both minerals and waste. In Poland, a particularly interesting option is the binding of CO2 through mineral carbonation of energy waste with a high content of CaO and limited economic use. Binding of CO2 has also been analyzed with use of the metallurgical slag and dust from cement kilns. Another option for mineral carbonation is the use of natural raw materials. To bind CO2 through mineral carbonation, minerals such as olivine, serpentine, and talc can be applied. This paper is a preliminary analysis presenting the possibility of using mineral raw materials to reduce carbon dioxide emissions. It also analyzes minerals occurring in Poland which can potentially be used to sequester CO2 in ex situ and in situ processes. [ABSTRACT FROM AUTHOR]

The process chain for Carbon Capture and Sequestration (CCS) includes tubing for injection of CO2 into saline aquifers. The compressed CO2 is likely to contain specific impurities; small concentrations of SO2and NO2 in combination with oxygen and humidity are most harmful. In addition, CO2 saturated brine is supposed to rise in the well when the injection process is interrupted. The material selection has to ensure that neither CO2 nor brine or a combination of both will leak out of the inner tubing. In this comprehensive paper the investigated materials range from low-alloy steels and 13% Cr steels up to high-alloy materials. Electrochemical tests as well as long term exposure tests were performed in CO2, in brine and combination of both; pressure was up to 100 bar, temperature up to 60 °C. Whereas the CO2 stream itself can be handled using low alloy steels, combinations of CO2 and brine require more resistant materials to control the strong tendency to pitting corrosion. The corrosion behavior of heat-treated steels depends on factors such as microstructure and carbon content. For different sections of the injection tube, appropriate materials should be used to guarantee safety and consider cost effectiveness. [ABSTRACT FROM AUTHOR]

This paper presents a risk assessment methodology for high pressure CO2 pipelines developed at the Health and Safety Laboratory (HSL) as part of the EU FP7 CO2Pipehaz project. Until recently, risk assessment of dense phase and supercritical CO2 pipelines has been problematic because of the lack of suitable source term and integral consequence models that handle the complex behaviour of CO2 appropriately. The risk assessment presented uses Phast, a commercially available source term and dispersion model that has been recently updated to handle the effects of solid CO2. A test case pipeline was input to Phast and dispersion footprints to different levels of harm (dangerous toxic load and probit values) were obtained for a set of pipeline specific scenarios. HSL's risk assessment tool QuickRisk was then used to calculate the individual and societal risk surrounding the pipeline. Knowledge gaps that were encountered such as: harm criteria, failure rates and release scenarios were identified and are discussed. [ABSTRACT FROM AUTHOR]

The paper deals with the computational fluid dynamics modelling of carbon dioxide capture from flue gases in the post combustioncapture method, one of the available carbon capture and storage technologies. 30% aqueous monoethanolamine solution was used as a solvent in absorption process. The complex flow system including multiphase countercurrent streams with chemical reaction and heat transfer was considered to resolve the CO2 absorption. The simulation results have shown the realistic behaviour and good consistency with experimental data. The model was employed to analyse the influence of liquid to gas ratio on CO2 capture efficiency. [ABSTRACT FROM AUTHOR]

The paper presents the results and analysis of biomass processing in order to provide the conditions for the most profitable use of the biomass in modern and efficient power generation systems with particular attention put on the decrease of the emission of carbon dioxide (CO2) and no need to develop carbon capture and storage plants. The promising concept of CO2 storage via the production of biochar and the advantages of its application as a promising carbon sink is also presented and the results are supported by authors' own experimental data. The idea enables the production of electricity, as well as (optionally) heat and cold from the thermal treatment of biomass with simultaneous storage of the CO2 in a stable and environmentally-friendly way. The key part of the process is run in a specially-designed reactor where the biomass is heated up in the absence of oxygen. The evolved volatile matter is used to produce heat/cold and electricity while the remaining solid product (almost completely dry residue) is sequestrated in soil. The results indicate that in order to reduce the emission of CO2 the biomass should rather be 'cut and char' than just 'cut and burn', particularly that the charred biomass may also become a significant source of nutrients for the plants after sequestration in soil. [ABSTRACT FROM AUTHOR]

Carbon Capture and Storage (CCS) is an essential tool in the fight against climate change. Any prospective storage site must meet various criteria that ensure the effectiveness, safety and economic viability of the storage operations. Finding the most suitable site for the storage of the captured CO 2 is an essential part of the CCS chain of activity. This work addresses the site selection of a second site for the Acorn CCS project, a project designed to develop a scalable, full-chain CCS project in the North Sea (offshore northeast Scotland). This secondary site has been designed to serve as a backup and upscaling option for the Acorn Site, and has to satisfy pivotal project requirements such as low cost and high storage potential. The methodology followed included the filtering of 113 input sites from the UK CO 2 Stored database, according to general and project-specific criteria in a multi-staged approach. This criteria-driven workflow allowed for an early filtering out of the less suitable sites, followed by a more comprehensive comparison and ranking of the 15 most suitable sites. A due diligence assessment was conducted of the top six shortlisted sites to produce detailed assessment of their storage properties and suitability, including new geological interpretation and capacity calculations for each site. With the new knowledge generated during this process, a critical comparison of the sites led to selection of East Mey as the most suitable site, due to its outstanding storage characteristics and long-lasting hydrocarbon-production history, that ensure excellent data availability to risk-assess storage structures. A workshop session was held to present methods and results to independent stakeholders; feedback informed the final selection criteria. This paper provides an example of a criteria-driven approach to site selection that can be applied elsewhere. • CO 2 storage site selection for the Acorn CCS project in the North Sea. • Criteria-driven approach based on geological, economic, and safety aspects. • Multi-staged methodology including filtering, comparison and ranking of sites. • East Mey selected thanks to its storage characteristics and hydrocarbon history. [ABSTRACT FROM AUTHOR]

SUMMARY The assessment for realistic CO2-adsorption capacities of different rocks is important for understanding the processes associated with CO2 storage. This paper investigates the adsorption characteristics of rocks for CO2 (limestone, sandstone, marl, claystone, clay, siltstone and metamorphic rock) by using a gravimetric method. The measurements were performed at 21°C with pressures from 1 up to 4 MPa. Sandstone (and clay with sand/sandstone) showed the largest adsorption capacity at 21°C. The highest amount of in situ CO2 contents in measured samples was 21.4 kg/t. The CO2-adsorption capacities were lower than past results in different coal samples. The results indicate that adsorption of CO2 into rocks may play an important role in storing CO2 in subsurface rock. Copyright © 2012 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Carbon Capture and Storage (CCS) is a very innovative and promising solution for greenhouse gases (GHG) reduction, i.e., capturing carbon dioxide (CO2) at its source and storing it indefinitely to avoid its release to the atmosphere. This paper investigates a set of key issues in the development of specific rules for the application of Life Cycle Assessment (LCA) to CCS. The following LCA-based information are addressed in this work: definition of service type, definition of functional unit, definition of system boundaries, choice of allocation rules, choice of selected Life Cycle Inventory (LCI) results or other selected parameters for description of environmental performance. From a communication perspective, the specific rules defined in this study have been developed coherently with the requirements of a type III environment label scheme, the International EPD® System, according to the ISO 14025 standard. [ABSTRACT FROM AUTHOR]

The CO2 capture and storage (CCS) technology is since more than ten years considered one of the key options for the future climate change mitigation. This paper discusses the implications for the further development of CCS, particularly with respect to climate change policy in an international geopolitics context. The rationale for developing CCS should be the over-abundance of fossil fuel reserves (and resources) in a climate change context. From a geopolitical point, it can be argued that the most important outcome from the successful commercialisation of CCS will be that fossil fuel-dependent economies with large fossil fuel resources will find it easier to comply with stringent greenhouse gas reduction targets (i. e. to attach a price to CO2 emissions). This should be of great importance since, from a geopolitical view, the curbing on greenhouse gas emissions cannot be isolated from security of supply and economic competition between regions. Thus, successful application of CCS may moderate geopolitical risks related to regional differences in the possibilities and thereby willingness to comply with large emission cuts. In Europe, application of CCS will enhance security of supply by fuel diversification from continued use of coal, especially domestic lignite. Introduction of CCS will also make possible negative emissions when using biomass as a fuel, i. e. in so called Biomass Energy CCS (BECCS). Yet, the development of BECCS relies on the successful development of fossil fuelled CCS since BECCS in itself is unlikely to be sufficient for establishing a cost efficient CCS infrastructure for transport and storage and because BECCS does not solve the problem with the abundant resources of fossil fuels. Results from research and development of capture, transport and storage of CO2 indicate that the barriers for commercialization of CCS should not be technical. Instead, the main barriers for implementation of CCS seem to be how to reach public acceptance, to reduce cost and to establish a high enough price on CO2 emissions. Failure to implement CCS will require that the global community, including Europe, agrees to almost immediately to start phasing out the use of fossil fuels, an agreement which seems rather unlikely, especially considering the abundant coal reserves in developing economies such as China and India. [ABSTRACT FROM AUTHOR]

Abstract: Hydrogen production from fossil fuels together with carbon capture has been suggested as a means of providing a carbon free power. The paper presents a comparative exergetic analysis performed on the hydrogen production from natural gas with several combinations of reactor systems: (a) oxy or air fired autothermal reforming with subsequent water gas shift reactor and (b) membrane reactor assisted with shift catalysts. The influence of reactor temperature and pressure as well as operating parameter steam-to-carbon ratio, is also studied exergetically. The results indicate optimal power plant configurations with CO2 capture, or hydrogen delivery for industrial applications. [Copyright &y& Elsevier]

Abstract: Geochemical modeling is a common tool to estimate the potential for storing supercritical CO2 in deep saline aquifers, and to predict the effects thereof. Geochemical models necessarily rely on thermodynamic relationships or “sub-models” to estimate quantities such as chemical solubility, activity, and fugacity. In this paper, we compare three proposed models for the fugacity of supercritical CO2, four proposed models for the activity coefficient of dissolved (aqueous) CO2, and four proposed models for the solubility of CO2 in aquifer brine. We examine the conditions under which estimates from these different proposed thermodynamic sub-models agree or disagree. Also, we develop a geochemical model that predicts the effects of injecting CO2 into a deep, saline, dolomitic-limestone aquifer; specifically, we predict the change in brine pH, the mineral precipitation/dissolution, and the potential solubility trapping of injected CO2 in response to the CO2 injection. We test nine different versions of the model, utilizing different combinations of the thermodynamic sub-models listed above. This allows us to quantify how key geochemical predictions depend upon the selection of thermodynamic sub-models. We find that different combinations of thermodynamic sub-models yield similar estimates for equilibrium pH and for quantities of mineral precipitation/dissolution, but that agreement is worse when predicting the equilibrium CO2 concentration in brine and/or the solubility trapping of CO2. These results indicate that the predicted equilibrium pH and mineral precipitation/dissolution are not very sensitive to the underlying thermodynamic sub-models, whereas estimates for the CO2 concentration in brine and potential solubility trapping are. Overall, the geochemical predictions are least sensitive to the choice of CO2 activity coefficient sub-model, are moderately sensitive to the choice of CO2 solubility sub-model, and are most sensitive to the choice of CO2 fugacity coefficient sub-model. [Copyright &y& Elsevier]

Carbon capture, transport and storage (CCS) is a very active field of research, because of its potential to make large reductions of emissions from fossil fuel combustion relevant to climate change. This paper reviews the recent and current work on practical injections of CO2 as research tests for storage projects and specifically focuses on industrial-scale or relevant injections into saline formations (about 1 Mt CO2 per year). All injection projects around the world have been reviewed, and 20 are reported to compile, depth, reservoir quality and injectivity, cost, and rate. This shows that testing of injection is concentrated onshore; however the projects with the highest total CO2 storage estimate are offshore. Pipeline transport systems are mostly used for the large projects. Formations targeted in the injection process are sandstone or carbonate. In the majority of cases initial projections of injectivity are confirmed in tests. A variety of monitoring techniques are used in all projects, these have detected CO2, but have not shown unexpected CO2 movement. Practical experiences of CO2 injection operations therefore suggest that similar operations can be successfully carried out in the saline formations of the UK North Sea and other large sedimentary basins. [ABSTRACT FROM AUTHOR]

The installations of CO2 capture from flue gases using chemical absorption require a supply of large amounts of heat into the system. The most common heating medium is steam extracted from the cycle, which results in a decrease in the power unit efficiency. The use of heat needed for the desorption process from another source could be an option for this configuration. The paper presents an application of gas-air systems for the generation of extra amounts of energy and heat. Gas-air systems, referred to as the air bottoming cycle (ABC), are composed of a gas turbine powered by natural gas, air compressor and air turbine coupled to the system by means of a heat exchanger. Example configurations of gas-air systems are presented. The efficiency and power values, as well as heat fluxes of the systems under consideration are determined. For comparison purposes, the results of modelling a system consisting of a gas turbine and a regenerative exchanger are presented. [ABSTRACT FROM AUTHOR]

Carbon dioxide capture and storage (CCS) links together technologies that separate carbon dioxide (CO2) from fixed point source emissions and transport it by pipeline to geologic reservoirs into which it is injected underground for long-term containment. Previously, models have been developed to minimize the cost of a CCS infrastructure network that captures a given amount of CO2. The CCS process can be costly, however, and large-scale implementation by industry will require government regulations and economic incentives. The incentives can price CO2 emissions through a tax or a cap-and-trade system. This paper extends the earlier mixed-integer linear programming model to endogenously determine the optimal quantity of CO2 to capture and optimize the various components of a CCS infrastructure network, given the price per tonne to emit CO2 into the atmosphere. The spatial decision support system first generates a candidate pipeline network and then minimizes the total cost of capturing, transporting, storing, or emitting CO2. To illustrate how the new model based on CO2 prices works, it is applied to a case study of CO2 sources, reservoirs, and candidate pipeline links and diameters in California. [ABSTRACT FROM AUTHOR]

Abstract: In this paper, different electricity demand scenarios for Spain are presented. Population, income per capita, energy intensity and the contribution of electricity to the total energy demand have been taken into account in the calculations. Technological role of different generation technologies, i.e. coal, nuclear, renewable, combined cycle (CC), combined heat and power (CHP) and carbon capture and storage (CCS), are examined in the form of scenarios up to 2050. Nine future scenarios corresponding to three electrical demands and three options for new capacity: minimum cost of electricity, minimum CO2 emissions and a criterion with a compromise between CO2 and cost (CO2-cost criterion) have been proposed. Calculations show reduction in CO2 emissions from 2020 to 2030, reaching a maximum CO2 emission reduction of 90% in 2050 in an efficiency scenario with CCS and renewables. The contribution of CCS from 2030 is important with percentage values of electricity production around 22–28% in 2050. The cost of electricity (COE) increases up to 25% in 2030, and then this value remains approximately constant or decreases slightly. [Copyright &y& Elsevier]

Geological carbon storage is an effective method capable of reducing carbon dioxide (CO2) emissions at significant scales. Subsurface reservoirs with sealing caprocks can provide long-term containment for the injected fluid. Nevertheless, CO2 leakage is a major concern. The presence of abandoned wells penetrating the reservoir caprock may cause leakage flow-paths for CO2 to the overburden. Assessment of time-varying leaky wells is a need. In this paper, we propose a new semi-analytical approach based on pressure-transient analysis to model the behavior of CO2 leakage and corresponding pressure distribution within the storage site and the overburden. Current methods assume instantaneous leakage of CO2 occurring with injection, which is not realistic. In this work, we employ the superposition in time and space to solve the diffusivity equation in 2D radial flow to approximate the transient pressure in the reservoirs. Fluid and rock compressibilities are taken into consideration, which allow calculating the breakthrough time and the leakage rate of CO2 to the overburden accurately. We use numerical simulations to verify the proposed time-dependent semi-analytical solution. The results show good agreement in both pressure and leakage rates. Sensitivity analysis is then conducted to assess different CO2 leakage scenarios to the overburden. The developed semi-analytical solution provides a new simple and practical approach to assess the potential of CO2 leakage outside the storage site. This approach is an alternative to numerical methods when detailed simulations are not feasible. Furthermore, the proposed solution can also be used to verify numerical codes, which often exhibit numerical artifacts. [ABSTRACT FROM AUTHOR]

• Economics of advanced IGCC plants for flexible power and hydrogen production. • Plants employ gas switching combustion and membrane-assisted water–gas shift. • CO 2 avoidance costs €25/ton compared to €44/ton for pre-combustion capture. • When the flexibility benefit is accounted for, CO 2 avoidance costs are almost zero. • Flexible power & H 2 production improves annual investment returns by 6%-points. Variable renewable energy (VRE) has seen rapid growth in recent years. However, VRE deployment requires a fleet of dispatchable power plants to supply electricity during periods with limited wind and sunlight. These plants will operate at reduced utilization rates that pose serious economic challenges. To address this challenge, this paper presents the techno-economic assessment of flexible power and hydrogen production from integrated gasification combined cycles (IGCC) employing the gas switching combustion (GSC) technology for CO 2 capture and membrane assisted water gas shift (MAWGS) reactors for hydrogen production. Three GSC-MAWGS-IGCC plants are evaluated based on different gasification technologies: Shell, High Temperature Winkler, and GE. These advanced plants are compared to two benchmark IGCC plants, one without and one with CO 2 capture. All plants utilize state-of-the-art H-class gas turbines and hot gas clean-up for maximum efficiency. Under baseload operation, the GSC plants returned CO 2 avoidance costs in the range of 24.9–36.9 €/ton compared to 44.3 €/ton for the benchmark. However, the major advantage of these plants is evident in the more realistic mid-load scenario. Due to the ability to keep operating and sell hydrogen to the market during times of abundant wind and sun, the best GSC plants offer a 6–11%-point higher annual rate of return than the benchmark plant with CO 2 capture. This large economic advantage shows that the flexible GSC plants are a promising option for balancing VRE, provided a market for the generated clean hydrogen exists. [ABSTRACT FROM AUTHOR]