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  • 1.
    Ahmad, Nawaz
    et al.
    KTH, School of Architecture and the Built Environment (ABE), Civil and Architectural Engineering, Hydraulic Engineering. Policy Wing, Ministry of Petroleum and Natural Resources, Government of Pakistan, Pakistan.
    Wörman, Anders
    KTH, School of Architecture and the Built Environment (ABE), Civil and Architectural Engineering, Hydraulic Engineering.
    Bottacin-Busolin, Andrea
    Sanchez-Vila, Xavier
    Reactive transport modeling of leaking CO2-saturated brine along a fractured pathway2015In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 42, p. 672-689Article in journal (Refereed)
    Abstract [en]

    One concern regarding the underground storage of carbon dioxide (CO2) is its potential leakage from reservoirs. Over short period of time, the leakage risk is related mainly to CO2 as a separate supercritical fluid phase. However, over longer periods upon complete dissolution of injected CO2 in the fluid, the leakage risk is associated with dissolved phase CO2. Over the geological time scales, large-scale groundwater motion may cause displacement of brine containing dissolved CO2 along the conducting pathways. In this paper, we present a comprehensive modeling framework that describes the reactive transport of CO2-saturated brine along a fracture in the clay caprock based on the future, hypothetical leakage of the dissolved phase CO2. This study shows that the transport of leaked dissolved CO2 is significantly retarded by a combination of various physical and geochemical processes, such as mass exchange between conducting fracture and the neighboring rock matrix through molecular diffusion, sorption and calcite dissolution in the rock matrix. Mass stored in aqueous and adsorbed states in the rock matrix caused retention of dissolved CO2 along the leakage pathway. Calcite dissolution reaction in the rock matrix resulted in consumption of leaking dissolved CO2 and reduced its mass along the leakage pathway. Consumption and retention of dissolved CO2 along the leakage pathway have important implications for analyzing the potential reduction of CO2 fluxes from storage reservoirs over large periods and long travel pathways.

  • 2.
    Ahmad, Nawaz
    et al.
    KTH, School of Architecture and the Built Environment (ABE), Civil and Architectural Engineering, Hydraulic Engineering. Ministry of Petroleum and Natural Resources, Pakistan.
    Wörman, Anders
    KTH, School of Architecture and the Built Environment (ABE), Civil and Architectural Engineering, Hydraulic Engineering.
    Sanchez-Vila, X.
    Jarsjö, J.
    Bottacin-Busolin, A.
    Hellevang, H.
    Injection of CO2-saturated brine in geological reservoir: A way to enhanced storage safety2016In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 54, p. 129-144Article in journal (Refereed)
    Abstract [en]

    Injection of free-phase supercritical CO2 into deep geological reservoirs is associated with risk of considerable return flows towards the land surface due to the buoyancy of CO2, which is lighter than the resident brine in the reservoir. Such upward movements can be avoided if CO2 is injected in the dissolved phase (CO2aq). In this work, injection of CO2-saturated brine in a subsurface carbonate reservoir was modelled. Physical and geochemical interactions of injected low-pH CO2-saturated brine with the carbonate minerals (calcite, dolomite and siderite) were investigated in the reactive transport modelling. CO2-saturated brine, being low in pH, showed high reactivity with the reservoir minerals, resulting in a significant mineral dissolution and CO2 conversion in reactions. Over the injection period of 10 yr, up to 16% of the injected CO2 was found consumed in geochemical reactions. Sorption included in the transport analysis resulted in additional quantities of CO2 mass stored. However, for the considered carbonate minerals, the consumption of injected CO2aq was found mainly in the form of ionic trapping.

  • 3. Chasset, Coralie
    et al.
    Jarsjo, Jerker
    Erlstrom, Mikael
    Cvetkovic, Vladimir
    KTH, School of Architecture and the Built Environment (ABE), Land and Water Resources Engineering.
    Destouni, Georgia
    Scenario simulations of CO(2) injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden2011In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 5, no 5, p. 1303-1318Article in journal (Refereed)
    Abstract [en]

    Deep saline aquifers have large capacity for geological CO(2) storage, but are generally not as well characterized as petroleum reservoirs. We here aim at quantifying effects of uncertain hydraulic parameters and uncertain stratigraphy on CO(2) injectivity and migration, and provide a first feasibility study of pilot-scale CO(2) injection into a multilayered saline aquifer system in southwest Scania, Sweden. Four main scenarios are developed, corresponding to different possible interpretations of available site data. Simulation results show that, on the one hand, stratigraphic uncertainty (presence/absence of a thin mudstone/claystone layer above the target storage formation) leads to large differences in predicted CO(2) storage in the target formation at the end of the test (ranging between 11% and 98% of injected CO(2) remaining), whereas other parameter uncertainty (in formation and cap rock permeabilities) has small impact. On the other hand, the latter has large impact on predicted injectivity, on which stratigraphic uncertainty has small impact. Salt precipitation at the border of the target storage formation affects CO(2) injectivity for all considered scenarios and injection rates. At low injection rates, salt is deposited also within the formation, considerably reducing its availability for CO(2) storage.

  • 4.
    Hu, YuKun
    et al.
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Energy Processes.
    Yan, Jinyue
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Energy Processes.
    Numerical simulation of radiation intensity of oxy-coal combustion with flue gas recirculation2013In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 17, p. 473-480Article in journal (Refereed)
    Abstract [en]

    Oxy-fuel combustion is one of potential technologies for carbon dioxide (CO2) capture in fossil fuel fired power plants. Characterization of flue gas composition in the oxy-fuel combustion differs from that of conventional air-coal combustion, which results in the change of radiative heat transfer in combustion processes. This paper presents a numerical study of radiation intensity on lateral walls based on the experimental results of a 0.5MW combustion test facility (CTF). Differences in the oxy-coal combustion are analyzed, such as flue gas recycle, absorption coefficient and radiation intensity. The simulation results show that an effective O2 concentration ([O2]effective) between 29 and 33vol% (equivalent to the flue gas recycle ratio of 72-69%) constitutes a reasonable range, within this range the behavior of oxy-coal combustion is similar to air-coal combustion. Compared with the air-coal combustion, the lower limit (29vol%) of this range results in a similar radiative heat flux at the region closed to the burner, but a lower radiative heat flux in the downstream region of the CTF; the upper limit (33vol%) of this range results in a higher radiative heat flux at the region closed to the burner, while a similar radiative heat flux in the downstream region of the CTF.

  • 5. Li, Hailong
    et al.
    Wilhelmsen, Oivind
    Lv, Yuexia
    Wang, Weilong
    Yan, Jinyue
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Energy Processes.
    Viscosities, thermal conductivities and diffusion coefficients of CO(2) mixtures: Review of experimental data and theoretical models2011In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 5, no 5, p. 1119-1139Article, review/survey (Refereed)
    Abstract [en]

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

  • 6. Li, Hailong
    et al.
    Yan, Jinyue
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Energy Processes.
    Campana, Pietro E.
    Feasibility of integrating solar energy into a power plant with amine-based chemical absorption for CO2 capture2012In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 9, p. 272-280Article in journal (Refereed)
    Abstract [en]

    Solar thermal energy has the potential to supply the thermal demand of stripper reboiler in the power plant with amine-based post combustion CO2 capture. The performance of a power plant integrated with solar assisted post combustion CO2 capture (SCC) is largely affected by the local climatic conditions, such as solar irradiation, sunshine hours and ambient temperature, the type of solar thermal collector and CO2 recovery ratio. The feasibility evaluation results about such a power plant show that the cost of electricity (COE) and cost of CO2 avoidance (COA) are mainly determined by the local climatic conditions. For the locations having higher solar irradiation, longer sunshine hours and higher ambient temperature, the power plant with SCC has lower COE and COA. COE and COA are sensitive to the prices of solar thermal collectors. In order to achieve lower COE and COA compared to the power plant integrated with non-solar assisted post combustion capture, the price of solar thermal collector has to be lower than 150 USD/m(2) and 90 USD/m(2) for the solar trough and vacuum tube, respectively.

  • 7.
    Nazir, Shareq Mohd
    et al.
    Department of Energy and Process Engineering, Norwegian University of Science and Technology, Trondheim, Norway.
    Morgado, Joana Francisco
    Department of Energy and Process Engineering, Norwegian University of Science and Technology, Trondheim, Norway;Department of Chemical Engineering, University of Coimbra, Coimbra, Portugal.
    Bolland, Olav
    Department of Energy and Process Engineering, Norwegian University of Science and Technology, Trondheim, Norway.
    Quinta-Ferreira, Rosa
    Department of Chemical Engineering, University of Coimbra, Coimbra, Portugal.
    Amini, Shahriar
    Department of Energy and Process Engineering, Norwegian University of Science and Technology, Trondheim, Norway;SINTEF Industry, Trondheim, Norway.
    Techno-economic assessment of chemical looping reforming of natural gas for hydrogen production and power generation with integrated CO2 capture2018In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 78, p. 7-20Article in journal (Refereed)
    Abstract [en]

    The current study presents the techno-economic analysis of the CLR-CC process. The CLR-CC process comprises of chemical looping reforming (CLR) of Natural Gas, water gas shift, CO2 capture and compression, and combined cycle power plant. A 1-D phenomenological model was developed using MATLAB and is used to study the performance of CLR, whereas the remaining part of the process was analysed using commercial software tools like Aspen and Thermoflow. The effect of design conditions in CLR, mainly the air flowrate to the oxidation reactor, oxidation reactor outlet temperature and the steam flowrate to the fuel reactor of CLR, on the overall techno-economic performance of the CLR-CC process is reported. The CH4 conversion in CLR, net electrical efficiency, CO2 avoidance rate and the Levelised Cost of Electricity (LCOE) have been identified as technoeconomic performance indicators. For the sensitivity study carried out in this study through 12 cases, the net electrical efficiency of the CLR-CC process varies between 40.0 and 43.4%, whereas the LCOE varies between 75.3 and 144.8 $/MWh, which is highly dependent on the fuel cost and process contingency rates.

    The full text will be freely available from 2020-08-01 15:53
  • 8. Nookuea, Worrada
    et al.
    Tan, Yuting
    KTH, School of Chemical Science and Engineering (CHE).
    Li, Hailong
    Thorin, Eva
    Yan, Jinyue
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Energy Processes. Mälardalen University, Sweden.
    Impacts of thermo-physical properties of gas and liquid phases on design of absorber for CO2 capture using monoethanolamine2016In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 52, p. 190-200Article in journal (Refereed)
    Abstract [en]

    Absorption of CO2 with aqueous amines in post-combustion capture is characterized as a heat and mass transfer processes with chemical reaction, which is sensitively affected by the thermo-physical properties of fluids. In order to optimize the design of the absorber of CO2 capture process, in this paper, the impacts of thermo-physical properties on the column design were investigated. Furthermore, the property impacts on the capital cost of the absorber unit were also identified and analyzed. Results show that the gas phase density has the most significant effect on the column diameter. Underestimation of the gas phase density of 10% may result in an increase of about 6% of the column diameter. For the packing height, the liquid phase density has the most significant effect. 10% underestimation of the liquid phase density may result in an increase of 8% of the packing height. Moreover, the effect from the liquid phase viscosity is also significant. For the annual capital cost, the liquid phase density also shows the most significant effect. Underestimation of the liquid phase density of 10% leads to the cost overestimation of $1.4 million for the absorption column for a 400 MW coal-fired power plant. Therefore, the development of the flue gas density model and liquid phase density and viscosity models of the aqueous amine solution with CO2 loading should be prioritized.

  • 9.
    Rexed, Ivan
    et al.
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Applied Electrochemistry.
    della Pietra, Massimiliano
    University of Perugia.
    McPhail, Stephen
    ENEA.
    Lindbergh, Göran
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Applied Electrochemistry.
    Lagergren, Carina
    KTH, School of Chemical Science and Engineering (CHE), Chemical Engineering and Technology, Applied Electrochemistry.
    Molten carbonate fuel cells for CO2 separation and segregation by retrofitting existing plants - An analysis of feasible operating windows and first experimental findings2015In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 35, p. 120-130Article in journal (Refereed)
    Abstract [en]

    Molten carbonate fuel cells (MCFC) used as active carbon dioxide concentrator units are a promising solution to reduce greenhouse gas (GHG) emissions from traditional combustion plants. The cell reaction transfers carbonate ions from the cathode to the anode and allows the fuel cell to simultaneously produce power and separate CO2 from a stream of flue gas. Carbon dioxide separation is of high interest for use in natural gas combined cycles and coal gas combustion plants, as a large part of anthropogenic CO2 worldwide originates from such installations. The flue gas from these types of combustion technologies typically contains 3-15% CO2, which is in the lower operational range of the MCFC. The aim of this work was to investigate the possibility to retrofit existing power plants with MCFC to reduce the total release of CO2 without necessarily reducing the power output, and to understand which kind of power plant could have the major benefits with an MCFC retrofitting. The performance of lab scale MCFC fed with simulated flue gas was evaluated, and a number of operational parameters, such as utilization factor and cathode humidification were varied to study the effect on fuel cell performance. The results show that it is feasible to operate the MCFC as a CO2 separator for simulated gas turbine flue gas; however, the voltage drop due to low CO2 concentration may restrict the operating window depending on various operating conditions.

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