Energy &Environmental Science View Article Online REVIEW View Journal | View Issue Carbon capture and storage update Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. Cite this: Energy Environ. Sci., 2014, 7, 130 M. E. Boot-Handford,a J. C. Abanades,b E. J. Anthony,c M. J. Blunt,d S. Brandani,e N. Mac Dowell,a J. R. Ferna´ndez,b M.-C. Ferrari,e R. Gross,f J. P. Hallett,g R. S. Haszeldine,h P. Heptonstall,f A. Lyngfelt,i Z. Makuch,f E. Mangano,e R. T. J. Porter,j M. Pourkashanian,k G. T. Rochelle,l N. Shah,a J. G. Yaoa and P. S. Fennell*a In recent years, Carbon Capture and Storage (Sequestration) (CCS) has been proposed as a potential method to allow the continued use of fossil-fuelled power stations whilst preventing emissions of CO2 from reaching the atmosphere. Gas, coal (and biomass)-fired power stations can respond to changes in demand more readily than many other sources of electricity production, hence the importance of retaining them as an option in the energy mix. Here, we review the leading CO2 capture technologies, Received 12th July 2013 Accepted 13th September 2013 available in the short and long term, and their technological maturity, before discussing CO2 transport and storage. Current pilot plants and demonstrations are highlighted, as is the importance of optimising the CCS system as a whole. Other topics briefly discussed include the viability of both the capture of DOI: 10.1039/c3ee42350f CO2 from the air and CO2 reutilisation as climate change mitigation strategies. Finally, we discuss the www.rsc.org/ees economic and legal aspects of CCS. 1. Introduction This paper discusses Carbon Capture and Storage (CCS), as one method to mitigate climate change. This paper will not assess the science behind anthropogenic climate change, the overwhelming evidence is presented by publications such as.1 The rationale for deployment of CCS on fossil-fuelled power stations (and possibly in the future with biomass-red stations) is that, when deployed in conjunction with other technologies (such as renewables and nuclear), the overall cost of electricity supply is minimised. This is because fossil-fuelled power stations are a Department of Chemical Engineering, Imperial College London, South Kensington, London, SW7 2AZ, UK. E-mail:
[email protected]; Tel: +44 (0)20 7594 6637 b Instituto Nacional del Carb´ on, (CSIC), Francisco Pintado Fe 26, 33011 Oviedo, Spain c Energy and Resource Technology Centre, Craneld University, Craneld, Bedford, MK43 0AL, UK d Department of Earth Science and Engineering, Imperial College London, South Kensington, London, SW7 2AZ, UK e SCCS Centre, School of Engineering, The University of Edinburgh, The King’s Buildings, Edinburgh EH9 3JL, UK f Centre for Environmental Policy, Imperial College London, South Kensington, London, SW7 2AZ, UK g Department of Chemistry, Imperial College London, South Kensington, London, SW7 2AZ, UK h SCCS, School of Geosciences, The University of Edinburgh, The King’s Buildings, Edinburgh EH9 3JW, UK i Chalmers University of Technology, 412 96 G¨oteborg, Sweden j Energy Technology and Innovation Initiative, University of Leeds, Leeds, LS2 9JT, UK k School of Process, Environmental and Materials Engineering, University of Leeds, Leeds LS2 9JT, UK l McKetta Department of Chemical Engineering, The University of Texas at Austin, Austin, TX 78712, USA 130 | Energy Environ. Sci., 2014, 7, 130–189 able to vary their output in response to changes in demand (or indeed to the supply from intermittent sources such as wind) and thus CCS reduces the need for large-scale energy storage to be developed. Carbon capture and storage refers to a number of technologies which capture CO2 at some stage from processes such as combustion (most generally for power generation) or gasication. Many industrial processes, most notably cement manufacture, iron and steel making and natural gas treatment also intrinsically produce CO2 and can be tted with CO2 capture technologies (and for these industries, CCS offers one of the very few remaining methods to reduce CO2 emissions where the best available technology in terms of e.g. energy efficiency is already used). The captured CO2 is then pressurised to 100 bar (or more), prior to being transported to a storage site, where it is injected into one of a number of types of stable geological features, trapping it for multiple hundreds or thousands of years and preventing its subsequent emission into the atmosphere. All of the individual components of the CCS chain, from capture all the way through to (and including) storage, have been demonstrated at or close to industrial scale. However, their integration into a single process is a signicant (but ultimately solvable) engineering challenge. There are a large number of different technologies for CCS, some closer to deployment than others. The purpose of this paper is to review the most recent developments in the eld, and not to introduce the topics. The interested reader is referred to a previous review, and a special edition of this journal for introductory material.2,3 Here, we discuss solvent scrubbing, oxyfuel combustion (for both pulverised fuel and in a uidised bed), chemical This journal is © The Royal Society of Chemistry 2014 View Article Online Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. Review looping and calcium looping, together with low-temperature sorbents, as exemplars of CCS technologies which might be commercialised within 10–20 years, (solvent scrubbing and oxyfuel potentially being commercialised towards the beginning of the period, with the other technologies towards the end, though we have included ionic liquids as a natural adjunct to solvent scrubbing even though these solvents are unlikely to be commercialised within 20 years). Of course, there are other technologies (such as membranes) which could also be considered, but are not covered here. We then move on to discuss a number of technologies that are either more niche or are further away from commercialisation (CO2 utilisation through mineralisation or in direct production of useful products). Transport of CO2 is then discussed, prior to storage. We then discuss the critical overarching themes: systems integration and policy design and implications for investment. Throughout this paper, where efficiency penalties are quoted, it should be noted that they are relative to a power station which will have an underlying thermal efficiency of between 40 and 60%. This means that an efficiency penalty of (say) 5% requires an increase in fuel-burn of 10% in order to produce the same amount of electricity. 1.1 Current power generation Despite recent global economic turmoil leading to appreciable reductions in global demand for oil and gas, demand for coal has if anything signicantly increased in the period since 2005. In 2010, world coal demand was approximately 5000 million tonnes of coal equivalent (Mtce). Under the IEA’s “Current Policies Scenario”, this is projected to grow to 7500 Mtce by 2035. It is worth noting that the entirety of this growth (in all scenarios) occurs in non-OECD countries. The share of global coal market arising from the non-OECD countries is expected to rise from 66% to 82%.4 Power generation is heavily dependent on coal-red plants throughout the world; in 2008, 41% of total global electricity was obtained by coal combustion (corresponding to 8273 TWh). While this share is expected to drop to 32% by 2035 (corresponding to 11 200 TWh), coal remains the dominant source of energy globally, with non-OECD demand doubling in the period to 2035. OECD demand for coal is expected to drop by as much as 33%—a result of a renewed “dash-for-gas” arising from the exploitation of reserves of shale gas (and other unconventional sources) and policies encouraging the reduction of the carbon intensity of power generation.4 Conventional or so called “sub-critical” coal-red power generating plants operate with low thermal efficiency (30–45%), which in turn incurs signicant fuel costs. This large fuel requirement will in turn increase exposure to fuel price volatility, thus increasing the investment risk associated with this technology. For these reasons, sub-critical power plants are expected to displaced by super-critical and ultra-supercritical power plants, reducing their market share from 73% in 2008 to 31% in 2035.4 Supercritical power plants are considered to be a promising option for future coal-based power generation as they operate with This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science higher base-load efficiency – in the range of 48–52%.5 Supercritical power plants operate with steam parameters in range of 240 bar/600 C and ultra-super critical plants which operate in the range of 350 bar/700 C/720 C or higher are under development. However, owing to the relatively high-priced materials required for their construction, the capital cost associated with supercritical power plants is relatively high6,7 and this is an active area of on-going research. For example, Yamamoto et al.8 reported the application of heat resistant material of high creep rupture strength and high oxidation resistance up to 650 C, which have already been developed for boilers and turbines of ultra-supercritical power plants. Viswanathan5 discussed the materials for ultrasupercritical (USC) plants to withstand operating steam conditions up to 760 C temperature and 35 MPa pressure, which are under development. 2. 2.1 Developments in amine scrubbing Thermodynamic context CO2 capture by post-combustion chemisorption relies on the separation of CO2 from ue gas using a chemical solvent. Thus, the thermophysical properties are of paramount importance in determining the potential of absorption, as it species interfacial phase equilibrium in addition to speciation in liquid phase and the enthalpy of absorption. Consequently, appropriate selection of a physical property model is of prime importance for the correct modelling of CO2 capture processes. In the context of CO2 capture, aqueous alkanolamine solutions are an extremely complex solution of molecular species, electrolyte species and reaction products and, on certain time scales, reaction intermediates. The physical property model must be applicable to all phases and chemical equilibria for a wide range of thermodynamic states. Several thermodynamic models have been used in the literature to represent the absorption of acid gases in alkanolamine solution, and they can be classied as one of three types: empirical models, equation of state approaches and excess Gibbs energy approaches. Empirical models are based on empirical mathematical relations, rather than theoretical considerations. Vapour-liquid equilibria (VLE) and chemical equilibria are represented in these models by tting numerical parameters on experimental data. The resulting correlations, such as that of Gabrielsen et al.9 for the partial pressure of CO2 as a function of the liquid phase CO2 loading, are oen easy to implement. However, as with all correlations, owing to their lack of theoretical underpinning, they are typically unsuitable for predictive calculation or extrapolation. Equations of state can be used to represent both liquid phase and gas phases (including electrolytes). Heterogeneous approaches, using the excess Gibbs energy to obtain activity coefficients in the liquid phase. These models typically need to be coupled with a separate model to describe the gas phase; this is oen a cubic equation of state. Homogeneous approaches are based on the Helmholtz energy; such as the formulation of Furst and Renon.10,11 Recently, the Statistical Associating Fluid Energy Environ. Sci., 2014, 7, 130–189 | 131 View Article Online Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. Energy & Environmental Science Theory12,13 (SAFT) for potentials of variable range14 (SAFT-VR) has been applied to aqueous mixtures of amines15 and alkanolamines16,17 and CO2. This new approach provides an implicit treatment of the chemical reactions and ionic speciation in these complex mixtures. Importantly, although the reaction products are also treated in an implicit fashion, it is possible to obtain an accurate description of the equilibrium carbamate/ bicarbonate products.17 As a consequence, when these thermodynamic models were incorporated in process models3,18 it was not necessary to describe the reaction products in the process model, nor was an enhancement factor required to describe the accelerating effect of the reactions on the mass transfer. This had the effect of signicantly reducing the size of the process models and consequently it was possible to use these detailed dynamic, non-equilibrium models to perform optimisation19 and control20 studies. It is noteworthy that the SAFT approach has been coupled with classical density functional theory approaches and has been used to predict vapour– liquid interfacial properties21 and the so-SAFT variant22 has also been used to describe the thermophysical properties and phase behaviour of ionic liquids in the context of CO2 capture.23 The third class of models uses the excess Gibbs energy to compute activity coefficients; they are oen based on alreadyexisting models for nonelectrolyte systems and extended with the Debye–Huckel theory to address electrolyte species. The model by Deshmukh and Mather24 is one of the simpler models, and parameters have been regressed for some amines25 it assumes ideality for water and calculates the activity coefficient for diluted species with a virial term for interaction between species. The model by Pitzer26 is quite similar and has been used to represent the solubility of CO2 in aqueous methyldiethanolamine (MDEA) and piperazine (PZ).27 Among the more elaborated models using the local composition of the mixture, the electrolyte-NRTL (e-NRTL) and extended UNIQUAC (e-UNIQUAC) models prevail. The e-NRTL model28,29 has been extensively used for CO2 absorption characterisation.30,31 The extended UNIQUAC32 provides the same theoretical basis as e-NRTL, with a simpler formulation, and it has already proved its ability to represent the alkanolamine system for CO2 absorption.33 The development of amine scrubbing has been focused on its application to coal-red power plants. Unless otherwise noted, the data and discussion on amine scrubbing that follows are based on the application to coal-red power plants. However, amine scrubbing should be useful for other applications. 2.2 Process owsheet The process technology using 30 wt% monoethanolamine (MEA) that has been evaluated by NETL34 to give a baseline for the solvent scrubbing process can no longer be used as a representative baseline for post-combustion capture. A number of vendors, including Fluor35 and MHI36 have developed processes and completed evaluations that give energy performances substantially better than that reported in the NETL analyses. In addition, a recent paper by Ahn et al. has illustrated all the different types of owsheet congurations for the amine scrubbing process.37 132 | Energy Environ. Sci., 2014, 7, 130–189 Review Fig. 1 gives an example of a second generation, optimised process for CO2 capture by amine scrubbing using 8 molal (m) piperazine (PZ).38,39 Compared to 30 wt% MEA it has twice the rate of CO2 absorption, 1.8 times the intrinsic working capacity, 5 to 10% lower heat of absorption (a disadvantage), and a maximum stripper T/P of 150 C/8 bar.40 In addition to the absorber, the process would probably include SO2 polishing with sodium alkali scrubbing and direct contact cooling of the ue gas before the PZ absorber. It would also usually include a water wash and aerosol removal aer the absorber. Much of this additional ue gas contacting could be incorporated into the same vessel as the CO2 absorption. 2.3 Overall energy performance 2.3.1 Reboiler heat duty. The measured and projected reboiler heat duty for CO2 capture from coal-red power plants by amine scrubbing has improved from as high as 5.5 MJ tCO21 in 2001 to as little as 2.6 in 2012 (Fig. 2). Early estimates used 20 wt% (MEA) with a simple stripper and absorber. Current systems assume 35 or 40 wt% MEA or other advanced amines with interheated strippers and intercooled absorbers or other comparable process improvements. With a Carnot cycle analysis, the minimum heat duty to separate 12% CO2 in ue gas and produce pure CO2 at 1 bar is 1 MJ t1. Therefore, the overall thermodynamic efficiency of the separation process is approaching 40%. 2.3.2 Equivalent work. Improvements in solvents and processes have reduced the estimated equivalent work to separate CO2 from coal-red ue gas from 450 kW h tCO21 removed in 2001 to as little as 200 kWh t1 in 2012 (Fig. 3). These values include CO2 compression to 150 bar and usually include pump work and fan work. The work value of the reboiler duty was estimated from a: Carnot efficiency based on the reboiler temperature (Treb, C) and assuming a 75% turbine efficiency, a reboiler approach T of 5 C, and a sink temperature of 40 C:41 Weq ¼ 0:75Qreb Treb þ 5 40 Treb þ 5 þ 273 (1) The compression work was estimated by a regression of results from Aspen modelling of an multistage compressor with intercooling to 40 C:41 8 150 > > 4:572 ln 4:096 Pin # 4:56 bar > < Pin kJ ¼ Wcomp > mol CO2 150 > > : 4:023 ln 2:181 Pin . 4:56 bar Pin (2) The improvements include thermally stable solvents such as piperazine, that can be stripped at 150 C to produce CO2 at 8 bar. Rochelle et al.40 present estimates of thermodynamic efficiencies for other common separation processes: desalination by reverse osmosis – 21%, distillation – 14 to 35%, and air separation – 25%. Since the minimum work for this separation is about 110 kWh t1, it is improbable that further improvement from the current thermodynamic efficiency of about 50% will This journal is © The Royal Society of Chemistry 2014 9 bar. Weq ¼ 30. PZ ¼ 40 wt% piperazine. KS-1 ¼ Proprietary MHI solvent.4 Fig. 1 includes removing heat to 40 C in direct contact cooling of the inlet ue gas. so CO2 capture by amine scrubbing will reduce the power output by 20 to 30%. the 5 K approach requires only 22 kJheat mol CO21 or 3.4. LB-2 ¼ case with Proprietary BASF/Linde process/solvent (Jovanovic et al. A typical coal-red power plant produces about 1000 kWh tCO21 emitted. the absorber should be operated at as low a temperature as possible with the available heat sink to maximise the rich and lean loading of the solvent. typically 5 to 10 K. taken in part from Rochelle et al. come easily.570 Fig.40 MEA ¼ monoethanolamine. Steam pressure should be reversibly reduced before it is used in the reboiler. Energy Environ. The design in Fig. Review Fig. Stripper bottom at 150 C/7. This maximises the pressure of the CO2 in the rst stage of the compressor. and trim cooling of the lean solvent feed to the absorber. (2011). 130–189 | 133 . In this example the steam pressure is 6 bar and could be consistent with steam extracted between the intermediate and low pressure turbine stages of a typical coalred power plant. intercooling in the middle of the absorber. 2 Reboiler heat duty for amine scrubbing on coal-fired power plants. KS-1 ¼ proprietary MHI solvent. Elevated stripper T also reduces the ratio of water vapour to CO2 in the simple stripper overhead... 2014. MEA ¼ monoethanolamine. With a typical working capacity of 0. Sci. In processes relying upon temperature swing regeneration.4. PZ ¼ 40 wt% piperazine.5 kJ mol1 CO2 ¼ 193 kW h per tonne CO2. 1 Energy & Environmental Science Intercooled Absorber/Interheated stripper with 8 m PZ. 2.41 Effective cross exchange between the cold rich and hot lean solvent eliminates much of the energy cost of operating with a large solvent rate. This journal is © The Royal Society of Chemistry 2014 Features of second-generation processes 2.4 kJequivalent work mol CO21 (with stripper at 120 to 150 C).5 kJ K1 kg(H2O + amine)1.569 TS-1 ¼ proprietary Toshiba solvent. H3 ¼ proprietary Hitachi solvent. Plate-and-frame exchangers appear to permit an economic approach T of 5 K.View Article Online Published on 13 September 2013. The equivalent work of the stripper and compressor system should be estimated from the work value of the steam heat and the compressor work to a nal pressure (typically 150 bar) by equations such as those offered by Van Wagener (above). the stripper should be operated at the maximum temperature allowed by solvent degradation or by the available heat supply. 2. 2012).568 LB1 ¼ Proprietary BASF/Linde solvent/ process. In processes relying upon temperature swing regeneration. Downloaded on 05/11/2015 11:56:07. 3 The total energy requirement for amine scrubbing to separate CO2 from coal flue gas and produce it at 150 bar.2 Stripper operating T. A cold rich bypass41 can be used to address imbalance between the heat capacities of the rich and lean streams. taken in part from Rochelle et al. The reboiler approach temperature should be minimised consistent with the tradeoff of reboiler capital cost and equivalent work loss.1 Absorber operating T and intercooling. 7. The example uses reboiler conditions of 150 C and 8 bar.5 to 4.8 mol CO2 kg(H2O + amine)1 and a heat capacity of 3. it is not energetically competitive because of the additional compression work for the CO2.8 0.61 0.4.38 This journal is © The Royal Society of Chemistry 2014 . These are summarised in Table 1 for a number of potential solvents.3 8.46 Solvents with a low heat of absorption (<60 kJ mol-1) will not be competitive.46 A quantitative measure of the effects of the heat of absorption and Tmax is the estimated reboiler pressure with a representative lean solvent.9 6.3 7. With a close exchanger approach T (5 K). 7.6 3.79 0.3 2.9 108 s1.41. Energy & Environmental Science Review 2.7 0.5 kPa exp((DHabs/R)(1/Tmax 1/313)) (4) As reviewed by Freeman45 and Rochelle.49 0.3 Advanced stripper conguration.35 0.41 and multipressure.42 A number of investigators are developing systems that increase the effective heat of absorption by precipitating solids out of the rich solution.1 Heat of absorption/Tmax/Pmax.66 0.5 kPa CO2 given by the expression: Pmax ¼ PH2O + PCO2 (3) where PH2O is the vapour pressure of water at Tmax and PCO2 is given by: PCO2 ¼ 0.63 0.44 Therefore. the stripper typically only removes enough CO2 from the rich solvent to leave the maximum lean loading that allows for adequate CO2 removal.2 5 7.4 8. In previous work Tmax has been dened as the temperature where the degradation rate constant is 2.4 Reversible stripping.17 1.1 7.5 9.08 0.43 The interheated stripper uses 10 to 20% less energy than a simple stripper.42 These include systems relying on sodium or potassium carbonate and tertiary or hindered amines with lower pKa values. 2.98 0.2 1.3 8.47.3 3.5.96 0.41 matrix.8 1.40 Table 1 This effect of thermal swing depends on the temperature of the reboiler which is limited by the thermal degradation of the solvent.4 1. When the lean loading (or solvent ow rate) is optimised to minimise energy consumption.35 0. Downloaded on 05/11/2015 11:56:07. 2014. 2.93 0.92 1.2 134 | Energy Environ.55 0..84 0.4.38 With an interheated stripper.78 1.41 Other congurations that work almost as well include adiabatic ash with compression.6 4.62 64 69 70 72 73 71 71 81 69 72 73 70 70 70 68 69 54 80 163 162 155 151 140 138 134 132 130 128 127 125 121 120 120 120 120 104 14.3 6.9 2. there is a tradeoff of sensible heat loss at high solvent rate (high lean loading) and stripping steam use at low solvent rate (low lean loading). The interheated stripper is the best of these (Fig.1 2. 3).5 Solvent selection for energy performance Three aggregated properties of solvents are related to energy performance.7 2.40 An intercooled absorber using a solvent with a fast rate of CO2 absorption (such as 8 m PZ) should be able to achieve 90% CO2 removal with a lean loading that gives an equilibrium CO2 partial pressure of 0.5 3. 2.28 0.0 4.5 7. anhydrous solvents or sorbents will not signicantly reduce the heat requirement by avoiding the vaporisation of water.23 0.5 3. Because amine scrubbing relies upon thermal swing regeneration.33 0. resulting in greater values of Pmax.45.9 3.41 0.68 0. Sci.7 0. Energy properties of amine alternatives49 Amine m kg0 Piperazine (PZ) PZ/bis-aminoethylether 2-Methyl PZ/PZ 2-Methyl PZ 2-Amino-2-methyl propanol (AMP) PZ/aminoethyl PZ PZ/AMP Diglycolamine (registered trademark) Hydroxyethyl PZ PZ/AMP 2-Piperidine ethanol Monoethanolamine (MEA) MEA Methydiethanolamine (MDEA)/PZ) MDEA/PZ Kglycinate Ksarconinate MEA/PZ 8 6/2 4/4 8 5 5/2 5/2.3 9.67 0. the difference between the CO2 loading at these rich (5 kPa CO2 at 40 C) and lean (0.View Article Online Published on 13 September 2013.46 the piperazine or piperazine derivatives have been identied as solvents with the greatest value of Tmax. 130–189 avg 107 Capacity mol kg1 Habs kJ mol1 Tmax C Pmax bar PH2O/ PCO2 0.6 5.37 0.5 kPa at 40 C) conditions will give a useful estimate of the working capacity of the solution. Many amines have lower values of Tmax because they degrade by formation of cyclic urea or by dimerisation through an oxazolidinone.25 0. Therefore.46 2.54 0. a greater heat of CO2 absorption always provides reduced energy consumption. less than 20% of the overhead vapour is water.81 0.41 cold rich bypass. These processes will ultimately have to deal with the reliability issues posed by precipitating slurries.3 10 8 2/4 8 11 7 5/5 7/2 6 6 7/2 8.15 1.1 5.42 two-stage heated ash. assumed to be saturated at 40 C to 0.73 0.67 0. Although vacuum stripping works with solvents that have a low heat of absorption.3 16.4 3.47 0. A number of stripper congurations are available to minimise the loss of heat as water vapour.48 One such system uses aqueous potassium carbonate with precipitation of potassium bicarbonate.1 5.99 0.5 kPa at 40 C and a rich loading that gives an equilibrium CO2 partial pressure of 5 kPa at 40 C.3 10.67 0.38 0. the same as that of 30% MEA at 120 C. (a tertiary amine) with piperazine and aminomethylpiperazine (a hindered amine) with piperazine are quite competitive. 2. These systems will probably not be energetically competitive with other second generation amine solvents that can be regenerated at 120 to 150 C. These values allow for a reasonable driving force to provide 90% CO2 removal at conditions of coal-red power plants.50–52 These phase change systems will usually provide greater capacity. A number of researchers are investigating systems that precipitate solids or separate a lean amine organic phase from the rich solvent. Downloaded on 05/11/2015 11:56:07. 7.b kg0 is a property of the amine.2 Other ue gas impurities. It can be measured in a wetted wall column or similar This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science device.35 However. It is probable that NO2 in the absorber inlet will be mostly absorbed by reaction with secondary and tertiary amines to produce nitrite. so Energy Environ.8.58 At 150 C. Inhibitors have been identied that are effective at absorber conditions. the enzymes are most effective in tertiary amines and carbonate solutions with low heats of CO2 absorption. CO2 typically absorbs by the process of diffusion with fast reaction in the boundary layer. Coal-red ue gas contains a number of impurities that impact processes for postcombustion capture. The value of kg0 at an average loading is given for a number of solvents in Table 1. The capacity and viscosity of the solvent are reected in the sensible heat requirement of the stripper. as opposed to two for the MEA system. Closmann56 and Voice57 have shown in benchscale experiments that even resistant amines are subject to reaction with dissolved and entrained oxygen that is carried into the high temperature of the cross-exchanger. One quantitative measure of the intrinsic solvent capacity is the difference between the equilibrium CO2 concentration at 40 C at 5 kPa CO2 and the equilibrium concentration at 40 C at 0. 130–189 | 135 .49 A number of amine systems provide greater normalised capacity than 7 M MEA. Piperazine or piperazine derivatives provide the greatest values of kg0 . A fast rate of CO2 absorption facilitates reversible absorber performance at high rich and lean loading that will minimise energy use in an optimised system. It can be minimised by stripping the dissolved oxygen from the rich solution with nitrogen or by a low-temperature ash of CO2/H2O.i P*CO2 . as reected in the normalised capacity given in Table 1.1 Oxidative degradation. HCl. Therefore. The normalised absorption ux of CO2 (kg0 .6 Normalised capacity – capacity/(m/10)0.25 power. Existing plants that treat coal-red ue gas include gas pretreating with sodium alkali scrubbing to remove practically all of the SO2. methyldiethanolamine. and not of the absorber contacting device.25.8 Solvent management 2. Furthermore. This oxidation rate depends on the solubility of oxygen in the solvent and can be substantially less than that in MEA solvents. and coarser yash.8. These convenient units of capacity reect the generalisation that the effective partial molar heat capacity of CO2 loading is typically near zero.56. tertiary amines. Monoethanolamine oxidises at absorber conditions with catalysis by dissolved iron and manganese.5 kPa.57 However. Tertiary amines and hindered amines are usually too slow to be used by themselves. the rate of CO2 absorption is an important energy parameter of the solvent.8. including piperazine. As shown in Table 1.54 Unfortunately they have not yet developed enzymes that are effective at elevated T (>100 C).55 These additives appear to degrade or are ineffective when used in cyclic systems with elevated T representative of strippers.View Article Online Review 2. it is appropriate to weight the intrinsic capacity by the viscosity to the 0. nitrite reacts with secondary amines to quantitatively produce nitrosamines. Secondary or primary amines are usually necessary to provide an acceptable rate of CO2 absorption. 2.25 Published on 13 September 2013.53. it is a nuisance and may be environmentally unacceptable in larger systems. Secondary amines will combine with NO2 in the inlet ue gas to produce nitrosamines that may create environmental risk in spills of disposal of spent solvent. MDEA is effective in inhibiting the oxidation of MEA at absorber conditions. Several investigators are developing carbonic anhydrase enzymes to catalyse the CO2 kinetics in otherwise slower solvents.58 At 100 to 150 C in the stripper.55 This oxidation rate seems to have been economically and environmentally acceptable in previous systems. and submicron H2SO4 aerosol.56 A number of amines are resistant to oxidation at absorber conditions. Tertiary amines appear to be oxidation inhibitors when used in blends with other amines. 2014. 2. given by: kJ Cp DT Qsensible (5) ¼ mol CO2 C where Cp is the heat capacity of the solvent (kJ kg(H2O + amine)1 K1). capacity/(m/10)0.3 Nitrosamines. Hindered and tertiary amines usually provide greater capacity because their intrinsic stoichiometry requires only 1 mol amine mol CO21. The optimum exchanger design will result in a greater approach DT with a greater viscosity. submicron y ash. nitrosopiperazine thermally decomposes. Hg. kg0 Because the optimisation of the absorber design will require lower rich and lean loading to achieve 90% CO2 removal with a reasonable amount of packing.. but they must deal with the reliability issues posed by precipitating slurries or two-phase systems. and C is the capacity of the solvent (mol CO2 kg(H2O + amine)1). 2. Sci. and hindered amines. This pretreating would not be expected to remove NOx. Greater capacity is also provided by diamines such as piperazine because more equivalents of amine can be loaded into the solvent before the viscosity becomes unacceptable. mol m2 Pa1) is given approximately by: pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi kam ðamineÞDCO2 Flux 0 kg ¼ ¼ (6) HCO2 PCO2 . DT is the hot side approach T of the cross exchanger.7 Rate of CO2 absorption. Greater solvent viscosity reduces the heat transfer coefficient in the cross-exchanger. Other vendors may be using amines such as hydroethylpiperazine with three or more hydrophilic groups that have practically no volatility and may not require a water wash. residual amine volatility at the top of the stripper can be managed to less than 1 ppm by a water wash. 2. are nonammable. 130–189 Review Amine scrubbing for CO2 capture from natural gas is commercially available..1 to 5 MWe.74 Aker Clean Carbon and MHI claim solutions to this problem. or ether. MDEA/PZ. (2) Effective plate-and-frame cross exchangers and high capacity solvents such as PZ/MDEA and PZ/AMP.67 Hindered amines and tertiary amines with methyl groups tend to have greater volatility. Seven prototype systems have been operated at 10 to 33 MW with coal-red ue gas and compression of the CO2. are more thermally stable. air emission of nitrosamine should pose negligible risk.62–64 The volatility of the nitrosamine is expected to be comparable to that of the parent amine.65 2. (2) Nitrosamines can be managed by avoiding secondary amines or by thermal or UV decomposition.58 Any gaseous emissions of nitrosamine should also be quickly decomposed by UV exposure in the atmosphere. 2014.7 MJ tCO21 and equivalent work less than 250 kWh tCO21 (including compression to 150 bar). Sci. There are no larger plants operating on coal-red gas.70–73 The resulting aerosol can be effectively removed by a bre lter mist eliminator with a pressure drop of 150 to 250 mmH2O. permitting. and a number of second and third generation solvents. Amine aerosols.9 Development status Since 1930. The Fluor applications include a 70 MWe gas-red boiler and a gas-red turbine with a ue gas rate equivalent to 80 MW of a coal-red boiler. dozens of plants have captured CO2 from combustion of methane or other clean fuels. 2.61 UV treating is being tested as a method to selectively decompose nitrosamine in amine solvents. (4) Fast amines such as piperazine and absorber intercooling that provide more reversible absorber operation with greater rich and lean loading. In solutions loaded with CO2. Vapour amine may condense in the absorber on submicron hydrophilic aerosol or particulate to produce small aerosol drops that are not removed by typical contacting internals in the absorber or water wash. Aliphatic monoamines without other polar groups have unacceptable volatility. (3) Congurations such as the interheated stripper that effectively recover heat from the stripper overhead. 136 | Energy Environ.76 More than 25 pilot plants have tested amine absorption/stripping on coalred ue gas at 0. Pilot plant data with piperazine-based solvent suggest a steady-state concentration of about 1 mM nitrosopiperazine at typical power plant conditions using a stripper at 150 C. The general area of IL use for CCS has been reviewed recently. (4) Amine aerosol losses can be eliminated by a bre lter. ILs have lower volatility. lower vapour pressure.59 This steady-state concentration will increase at lower stripper T and with ue gas containing more NO2. and FEED. and are easier to recycle. Downloaded on 05/11/2015 11:56:07.69 Several pilot plants have reported amine emissions as high as 200 ppm from pilot plants with 1 to 3 ppm SO3 in the inlet ue gas. (5) Amines with high heat of CO2 absorption that maximise the energy performance of thermal swing regeneration.8.77–84 In addition to a potentially lower demand for energy in the solvent regeneration step. This journal is © The Royal Society of Chemistry 2014 . diamines such as piperazine are substantially less volatile because of speciation to ions including protonated amine and carbamate. Nguyen66 measured amine volatility in water and showed that two or more hydrophilic groups usually produce an amine volatility less than 100 ppm at absorber lean conditions.View Article Online Published on 13 September 2013. natural gas. Ionic liquids as alternative solvents for CCS It has been suggested that the use of ionic liquids (ILs) as alternative solvents would have many advantages over conventional amine-based CO2 extraction. 7. Amine solvents that do not include secondary amines may still be subject to this reaction with oxidative and thermal degradation product of the primary or tertiary amines that make up the solvent.10 Conclusions Advanced amine systems will capture CO2 with heat duty less than 2. so other solvents and conditions may experience greater steady-state concentration. Because practical amines usually include at least two or more hydrophilic groups such as amine. The innovations contributing to reduced energy use include: (1) Thermally stable amines such as 8 m piperazine that can be regenerated at elevated pressure. Several investigators68 have been developing systems with amino acids (partially neutralised by K+) which should be nonvolatile ions. but one is under construction at 120 MW and another eight plants at 140 to 765 MW in various states of planning. The plants use monoethanolamine. Energy & Environmental Science it will reach a steady-state concentration where the rate of decomposition is equal to the rate at which NO2 enters the absorber. and other gases that contain little oxygen. Since 1980. Most are based on technology provided by Fluor (MEA. Economine) or MHI (KS-1). Therefore. Two public databases demonstrate that amine scrubbing is near commercial on coal-red power plants. (3) Vapour losses of amine can be avoided by water wash with volatile amines or by using non-volatile amines. diethanolamine.74 This problem could also be addressed by using an amine or amino acid with low or no volatility.75. alcohol.4 Amine volatility Vapour losses.60 Nitrosodiethanolamine has been found in monoethanolamine solvent. Remaining issues of secondary environmental impact with advanced amines have acceptable solutions: (1) Amine oxidation can be minimised by using amines such as piperazine and MDEA that are resistant to oxidation and by stripping dissolved oxygen at <100 C. 3. hundreds of plants have used amine scrubbing to remove CO2 from hydrogen. 3 46.1 36. Energy Environ. Henry’s law constants for CO2 in a range of different ILs are shown in Table 2. this anion can be employed to test designer cations (as it is the most likely to yield favourable physical properties) and yield salts with generally favourable CCS potential. Sci. (a) 1.6 0. (c) alkylpyridinium [Cnpyr]+.8 48.95 but also the solubility and affinity of the IL for water. the high molar solubility of CO2 with increasing n-alkyl chain length is largely a function of the increase in molecular weight of solvent.1 0. The recent developments in this eld will be reviewed here. The origin of the anion effect on CO2 solubility in ILs has been investigated through molecular dynamics86 where the anion–CO2 interactions were shown to be the strongest solvation forces present. but this effect is less dramatic than the molar solubility change and must be carefully considered when selecting IL cations. this is not a case of nding a solvent with a low heat of regeneration.9 0. [ace] ¼ acesulfamate.6 0.0 0.4 33.3 32. Downloaded on 05/11/2015 11:56:07. density and surface tension.94 This not only includes the solubility of CO2 and the strength of the IL–CO2 interactions in solution.90 While ILs typically have higher viscosities than common organic solvents and water at the same temperature91 (resulting in slower CO2 absorption kinetics).94 Most IL research has focused on salts with dialkylimidazolium cations ([CnCmim][X]).5 0.88 This increased viscosity causes poor gas diffusion and slow mass and heat transfer. This opens up the cation for specic tailoring to include CO2-philic moieties because it is the easiest portion of an IL to synthetically modify. such as heat capacity.2 Ion selection Anion effects on most IL-based solvation processes are dominant.93 Care is necessary to ensure that overall energy requirements are minimised by the use of any new solvent. (e) tetraalkylphosphonium [CwCxCyCzP]+.4 44.2 0.1 0. The highest solubility of CO2 recently reported was in [C5C1im][bFAP].8 28. Published on 13 September 2013. very high thermal stabilities (a measure of the thermal stability. 3. The volumetric solubility of CO2 does still decrease with increasing cation alkyl chain length. As a general rule.0 0.85 [eFAP] ¼ tris(pentafluoroethyl)trifluorophosphate.92 These favourable properties can result in a low energy requirement for solvent regeneration. [sac] ¼ saccharinate H (bar) Cation Anion 25 C [C4C1im] [C4C1im] [C6C1im] [C6(3C1)py] [(C6H4F9)C1im] [(C8H4F13)C1im] [C6C1im] [C6C1im] [C5C1im] [C6C1im] [C6C1im] [Et3NBH2C1im] [PF6] [NTf2] [NTf2] [NTf2] [NTf2] [NTf2] [eFAP] [pFAP] [bFAP] [ace] [sac] [NTf2] 53. This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science Table 2 Henry’s Law constants for CO2 in selected ILs. increasing the length of the alkyl side chain on the imidazolium cation improves CO2 solubility.N-dialkylpyrrolidinium [CnCmpyrr]+.2 21. For bulk liquid CCS applications.3 25. 2014. (h) hexafluorophosphate.9 132.2 81. Tonset of 400–500 C) and low melting points (50– 0 C).7 0. Data is taken from Muldoon et al. (b) N. enabling an easy comparison of various anion effects.1 33.80 other IL physical properties are Fig. (i) tetrafluoroborate. resulting in an open uid structure that dissolves CO2.7 potentially better than conventional organic solvents. 3.4 27. That study also pointed to mixtures on ILs with molecular solvents providing an optimised hybrid solution for CCS.2 19.2 113. 4 Selected IL cation and anion structures.1 1.6 20.2 60 C 0.1 0.1 16. and the implications of IL physical properties and functionalisation on CO2 solubility will also be explored. [bFAP] ¼ tris(nonafluorobutyl)trifluorophosphate.5 42. (g) trifluoromethanesulfonate [OTf].94 This naturally leads to selectivity problems when encountering wet ue gases.. 130–189 | 137 . which contains a highly uorinated alkylphosphate anion that is exceedingly noncoordinating.9 45.3 0.0 31. Density increases roughly linearly with increasing alkyl chain length87 while viscosity increases dramatically.86 However. As discussed above in the section on solvent scrubbing. as many ILs with highly basic anions absorb very large quantities of water.3 48.89.3-dialkylimidazolium [CnCmim]+. prominence is obviously placed on hydrophobic (water-immiscible) ILs.2 0. as most physical properties suffer when the alkyl chain length exceeds octyl.3 0.96 This anion also possesses poor interactions with water (leading to highly hydrophobic ILs) and generally favourable physical properties: relatively low viscosities (20–50 mPa s). 4) or employing mixtures. resulting in larger unit operations.6 32.2 0. [pFAP] ¼ tris(heptafluoropropyl)trifluorophosphate.3 0. including absorption columns and heat exchangers. (d) tetraalkylammonium [CwCxCyCzN]+. 7.View Article Online Review The comparison of ILs with molecular organic solvents has been discussed in a recent review3 and also discussed the general implications of changing the cation and anion (see Fig.2 0. (f) bis(trifluoromethylsulfonyl) imide [NTf2].85 As can be seen from Table 2. The bistriuorosulfonylimide [NTf2] anion generally gives the best CO2:N2 selectivity and high overall CO2 solubilities with most IL cations.1 Relationship between IL physical properties and CO2 solubility Henry’s constant is a quick and useful measure of CO2 solubility in ILs. 4. 5). Also. which is quite challenging in practice.107–109 Potential advantages of using amino acids include their low cost.77 3. the absorption capacity is greatly improved due to the acetate anion partially deprotonating the C2 position of the imidazolium ring. but very large when added to the anion.101 These basic ILs have more rapid absorption rates with little increase in viscosity.2 Amine-functionalised and amino-acid ionic liquids (AAILs). The increase in CO2 solubility is minimal when the peruoroalkyl chains are employed on the cation of the IL. however. Increasing the cation alkyl side chain length increases CO2 solubility.105 The salt (2hydroxyethyl)-trimethyl-ammonium(S)-2-pyrrolidine-carboxylic acid salt or [Choline][Pro] has been demonstrated to be able to capture and release CO2. a lower heat of absorption can lead to a higher overall energy requirement. only some functionalisation strategies have increased CO2 capacity.80 The synthetic exibility of ILs means that a nearinnite range of functionalisations are possible. further measurements are necessary under a CO2 atmosphere). 7. which will likely increase the expenses.1 Fluorinated ILs. likely by increasing the available volume for CO2 due to a decrease in cation–anion interactions. However. these modications are generally avoided due to environmental concerns surrounding peruorocarbons. some concern over melting point changes when amino acid anions absorb CO2.113 Though this will only occur under strictly anhydrous conditions. However. This eld of task-specic ILs (TSILs) for CCS applications has recently undergone rapid growth. 130–189 Review tributylphosphonium ILs (coupled with amino acid anions) exhibiting the best physicochemical properties. while functionalised (taskspecic) ILs are usually designed to chemically bond to CO2 in an absorption process. Incorporation of peruoroalkyl groups in ILs increases CO2 solubility compared to nonuorinated inorganic anions such as nitrate and dicyanamide.111 As mentioned above. but not overall: as discussed above. Oxygen-containing functional groups can serve as alternative sources of interaction with the electron-poor carbon atom of CO2 with similar effect.6 C) and thermal stability to above 200 C.View Article Online Energy & Environmental Science Published on 13 September 2013. increasing the overall absorption capacity.104 provide chemisorption at the stoichiometric ratio of IL : CO2 of 2 : 1 as with amine-based solvents. Downloaded on 05/11/2015 11:56:07. there is currently no comprehensive model for gas solubility in ILs.99 It is clear that there are mainly physical phenomena (such as dispersion forces) dominating CO2–IL interactions when unfunctionalised ILs are employed. 3. the unprotected N-heterocyclic carbenes can lead to unstable side reactions. 2014.102 These ILs also require extra synthetic and purication steps to produce. Amine character can be inserted into either the cation or the anion of the IL. pyridinium. However.97 However. Amine-functionalised side chains103.77 One way to overcome the viscosity problem is to use a solid support. There is.102 3.7 to 29. this is not ideal as a large amount of water needs to be evaporated to regenerate the IL. though this is likely to be very sensitive to water as these are hydrophilic anions. though cost and stability become important considerations. though the nature of the carbamate complex is still under dispute.110 Immobilisation of AAILs into nanoporous PMMA microspheres has recently been shown to increase CO2 uptake rates and ease regeneration.82 A variety of imidazolium or tetraalkylphosphonium cations have been combined with amino acid anions to make AAILs. forming an in situ carbene that reacts with CO2 to make a zwitterionic carboxylate. Much interest surrounds the use of ILs containing carboxylate anions for a variety of applications.105 A variety of cations (imidazolium.102 This can be attributed to the large affinity of CO2 for the peruoroalkyl chains. with only weak chemical complexes forming. amine-functionalised ILs tend to be highly viscous. where CO2 is released by bubbling N2 in the solution106 (of course.112 [C2C1im][OAc] has been shown to uptake almost 2 molar equivalents of water.113 This journal is © The Royal Society of Chemistry 2014 . with (3-aminopropyl)- 138 | Energy Environ. However.3 Conventional ILs Unfortunately. primarily in bioenergy. conrmed by FTIR and isolated as a crystalline product (Fig. this requires solid/ gas exchange.4. The structural exibility of ILs allow tuning of the enthalpy of absorption by employing basic ionic liquids made by neutralising tetraalkylphosphonium hydroxide with weak proton donors with different pKa values. The conventional MEA process solves the viscosity problem by diluting the MEA with water.82 3.4. these ILs generally have poorer thermal stabilities and higher melting points and viscosities than conventional ILs. 3. such as a low glass transition temperatures (in the range from 69. This results in a lower energy requirement than for amine solutions in the regeneration step.112 aer which the basic acetate ion absorbs CO2 which reacts with the water to form bicarbonate salts. ammonium and phosphonium) have been be functionalised with amines for CO2 capture.98. biodegradability and low toxicity. and also results in the hindrance of CO2 diffusion rates. which leads to problems of measuring CO2 capacity and developing handling strategies. Surprisingly.103 Unfortunately. AAILs can increase CO2 capture because they possess both carboxyl and amine functional groups and the IL can complex CO2 in a 1 : 1 stoichiometric ratio. Fig. the regeneration step can still be carried out under mild conditions with an appropriate stripping gas.80 Under anhydrous conditions.100 The enthalpy of CO2 physical absorption by these ILs is generally about 20 kJ mol1. some general trends can be observed. Sci. Amino-functionalised ILs provide strong complexation potential with CO2 by duplicating much of the amine character of molecular CCS solvents. 5 Reaction of CO2 at the C2 position with in situ-generated carbine.3 Carboxylate ILs.4 Task-specic ILs Conventional ILs mostly use physical absorption to capture CO2 through the space between ions.. polymerisable ILs as membranes could be a possible option for CO2 separation. based on amidinium (i.63 mPa s). and can be achieved in under 10 min.04 molar equivalents of CO2.3 mmHg CO2. including very high thermal and chemical stabilities.4 Reversible ILs. which are roughly analogous to polymerised versions of [CnCmim][BF4].129 Fig. Fig. the capture capacity can reach an equimolar ratio as shown in Scheme 2. 130–189 | 139 . including tethering of the alcohol group to the base.4. It may be that they are a potential choice for sorbent and membrane material for CO2 separation. BIMT) and the IL [bmim] [BF4] as a function of time (592.04 : 1 (relative to base) have been reported for this strategy. poly[1-(4-vinylbenzyl)-3-butylimidazolium hexauorophosphate] (PVBIH). 3. and Scheme 2 Proposed mechanisms of CO2 capture by AAILs: (a) and (b) without water. and poly[2-(1butylimidazolium-3-yl)ethyl methacrylate tetrauoroborate] (PBIMT). VBIT.4. To avoid this. tetramethylguanidine). DBU) or guanidinium alkylcarbonate salts.100 3. Poly(ionic liquid)s are a new technology for CO2 capture.114–119 The “molecular” state of the system consists of a 1 : 1 mixture of a proton donor (i. However. 22 C).130 However. there remain drawbacks. overcoming many of the viscosity limitations on uptake rate. though the higher volatility of the alcohol component may hinder deployment. Unfortunately. in the presence of small amounts of water (1% by mass).127 These TSILs contain functional groups capable of chemically complexing with CO2.124 which would imply sensitivity of CO2 absorbance to H2O presence. 7. the alcohol group can be incorporated into an IL cation side chain. 2014.128 AAILs supported on porous silica displays higher efficiency then when used as a bulk liquid phase.126 SILMs can be used to separate organic compounds. Reversible ILs. 6 CO2 absorption of three poly(ILs) (PVBIH.123 CO2 release can be achieved by mild heating (90–120 C) and the IL re-used. These supported TSILs achieve 2 : 1 IL : CO2 capture capacity through carbamate formation. SILMs have many potential advantages in CO2 capture. extremely low volatilities and increased contact area between the gas and ILs. Functionalised protic ILs can dissolve large quantities of CO2 under anhydrous conditions. In order to overcome this limitation. Review Energy & Environmental Science 3.View Article Online Published on 13 September 2013.131 Energy Environ.122 This journal is © The Royal Society of Chemistry 2014 facilitates CO2 transport through the membrane. and ions. MTBD.g.e.7 Poly(IL)s. 6 shows CO2 absorption data for three type of poly(IL)s: poly[1-(4-vinylbenzyl)-3-butylimidazolium tetrauoroborate] (PVBIT). these specic ILs are unlikely to be stable in the presence of water.129 A combination of SILMs and TSILs may be a better choice for CO2 capture at elevated temperatures and pressures. then a strong CO2 complex can be formed. They show higher selectivity in CO2 separation than [C4C1im] [NTf2] for CO2–CH4 gas mixtures because the amine group Scheme 1 CO2 capture mechanism for reversible ILs. 3.5 Protic ILs.131–134 Moreover. which is 20 times higher than the solubility in the neat IL. including leaching of the IL through membrane pores when the pressure drop is higher than the liquid stabilising forces within the matrix.81 CO2 can be successfully separated from N2 and CH4 by polymer lms of ILs which are polymerised by styrene and acrylate monomers.4. mixed gases. though these ILs will be very hydrophilic. PBIMT) and their corresponding monomers (VBIH. Sci.123 CO2 absorbances of 1. The use of ILs in membrane separation is a growing eld. PVBIT and PVBIH have been reported to take only 4 min and PBIMT only 3 min to reach 90% capacity. Functionalisation of the guanidines or amidines. and shows excellent CO2 capacity and good CO2 : N2 selectivities (Scheme 1). PVBIT. alcohol) and organic base. also show good CO2 reactivity and high absorption capacity.120 If a weak acid is employed.4. those based on uorinated alcohols have been shown to capture 2. The absorption and desorption of CO2 by poly(IL)s is faster than bulk ILs..6 Supported ionic liquid membranes (SILMs).120–122 These new ILs are interesting CO2 capture options. (c) with water. though would not be energetically viable in a power generation context. desorption by vacuuming is completely reversible.101. such as [(3NH2)C3C1im][NTf2] and [(3NH2)C3C1im][OTf] have also been explored. CO2 may actually react with the IL cation. Downloaded on 05/11/2015 11:56:07. It should be noted that for very strong bases (e. and the viscosities of these salts is relatively low (8. The SILMs based on task-specic TSILs. One way to overcome the high cost of dialkylimidazolium cation synthesis is to use protic ILs. which are acid–base complexes.e.125 may avert these difficulties. the global research activity has increased to the point where several demonstration phase projects have begun and the commercial concept is expected before 2020.87 Lower cost options. the VBIT and VBIH monomers did not absorb CO2 because of their crystalline structure. The ue gas stream should be cooled.138 4. An advantage of pressurised systems is that the combustion power cycle utilises the higher heating value of the fuel and produces more gross power compared to conventional atmospheric oxyfuel combustion power systems.e.1 times higher than [C4C1im][BF4]. as opposed to simply investigating interesting chemistry. Poly(IL) s with [PF6] anions displayed higher efficiency than [BF4] or [NTf2] based polymers and higher absorption and desorption rates. Oxyfuel combustion technology Oxyfuel combustion is one of the most developed technologies for carbon capture and storage. recycle loop. and the liquid BIMT monomer had the same absorption capacity as [C4C1im][BF4]. Energy & Environmental Science around 30 min to reach their full capacities. Interestingly. such as using oligo(ethylene glycol) or nitrile-containing alkyl groups. i. the implementation of oxyfuel operation will lead to a number of plant conguration changes and additional unit operations. amine–TSILs form strong chemical complexes with CO2. These biopolymers are environmentally friendly. oxyfuel combustion does allow for process exibility and improved combustion efficiency. One strategy to reduce the energy penalty is the use of pressurised oxyfuel combustion cycles. The combustion of fuel in an oxygen and RFG mixture was proposed in the early 1980s for the purpose of producing a high-purity CO2 stream for use in Enhanced Oil Recovery (EOR)139 and for simultaneously reducing greenhouse gas emissions from fossil fuel energy generation.1% higher than the IL) under mild conditions (30 C. Downloaded on 05/11/2015 11:56:07. scrubbed and dried before being diverted for the primary recycle. but it cannot disrupt the crystalline domains of chitosan. During the last decade. Higher capacities were also reported for the poly(IL)s. Several options for conguration of a secondary recycle stream exist.93. perhaps by lowering ion–ion interactions. A recent review83 highlights the most relevant advances. The optimum recycle ratio is generally 0. monomeric BIMT and [C4C1im][BF4] required more than 400 min to reach their equilibrium capacity. the overall plant efficiency is reduced by 8–12%. this yields oxygen levels in the oxidant environment that typically range from 25 to 30% because at these conditions. Unlike conventional fossil fuel-red power stations that use air as the oxidant.145 However. an oxy-red plant employs an Air Separation Unit (ASU) to produce an oxygen stream. though this will complicate synthesis.131 indicating that the polymeric structure itself conferred greater CO2 capacity.7. such as ILs should compare their rates of uptake to those of standard solvents.134 The efficiency of polymeric structures can also be enhanced by modifying the monomers. 2014. the reverse trend is observed for poly(IL)s. CO2 purication and compression. 4. By comparison. which has been studied by simulation. possibly due to steric hindrance. 130–189 Review fuel being burned in a mixture of oxygen and recycled ue gas (RFG). the ame and heat transfer characteristics reasonably approximate those of air-red pulverised fuel (PF) boilers.131 However. can absorb nearly 1 : 1 CO2. reliability and high carbon content of the fuel.136 The result is that chitin–IL and chitosan–IL mixtures have increased CO2 sorption capacity (8. Flue gas oxygen content is typically 3%..and intramolecular hydrogen bonds. There are two hydroxyl groups in chitin while there is an additional amine group in chitosan. CO2 dissolves in free volume spaces within the IL matrix without greatly affecting the structure. Surprisingly. biodegradable and almost non-toxic. natural gas or blends of biomass and coal.View Article Online Published on 13 September 2013.5 Molecular simulations of CO2 with ILs There have been a number of molecular simulation studies focused on the dissolution of CO2 in ILs.137 This is also likely responsible for the lower regeneration energy. ASU. Most interest has focused on oxy-coal combustion due to the abundance. Using current technology.135 Biopolymers (chitin and chitosan) also have been used in the process of CO2 capture. including coal (oxy-coal combustion). Oxygen excess levels are 15–20% for air-ring conditions but are kept lower for oxyfuel conditions to no more than 10% in order to minimise ASU operational costs. The following sections refer to oxy-coal combustion unless otherwise stated. Elevated dew point and higher available latent This journal is © The Royal Society of Chemistry 2014 . The IL [C4C1im]Cl has been used as a solvent to break the strong inter. There are many potential environmental and performance benets from using such recyclable.144 4. described above. The recycle is necessary to moderate the otherwise excessively high ame temperature that would result from burning in pure oxygen.2 Energy performance Oxyfuel combustion induces an energy penalty to the process caused by the requirements of producing O2 and compressing CO2. 1 atm CO2 pressure in CO2 xation and release processes). They must also regenerate the CO2 under an atmosphere of CO2 to demonstrate reaction reversibility. accounting for the rather unusual solubility proles. Oxyfuel combustion refers to 140 | Energy Environ. The oxygen stream is combined with RFG to produce an oxygen enriched gas for the oxidant. In conventional ILs. high-purity CO2 is produced.136 3. renewable. Sci. non-corrosive and non-volatile CO2 absorption media. 7. if the aim is to develop a replacement industrial-scale technology. Oxyfuel combustion can be applied to several fuels.140 Pilot scale studies were subsequently carried out141–143 in the following decades. such as triethylene tetramine lactate. By contrast.1 Process considerations In comparison to air-red plants. Aer the removal of water and other impurities from the ue gas exhaust stream. Particulates are removed in order to avoid accumulation of solids in the boiler and prevent the ue gas recirculation fan and gas passages from unnecessary wear due to erosion. these gures should be taken in context with the extremely rapid reactions of solvents such as MEA and PZ. as the CO2–IL interactions are relatively weak. while increasing the alkyl chain length of ILs signicantly increases gas permeability and diffusivity. up to 2. Studies of any new solvent. Conventional primary and secondary measures can be used for NOx control under oxyfuel operation. ash deposition and increased acid dew point. employing low NOx burners. The membrane used in the three-end concept is only exposed to air.8% for three-end concept. which will lead to a reduction in capital costs. Current investigations into OTM technologies are at the conceptual or laboratory scale. The different process conditions encountered in the three.149 This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science 4. Only a few studies have reported the extent of mercury oxidation or its retention in y ash. However.164 The oxyfuel process using RFG results in a higher concentration of SO2 (ppm) in the combustion ue gas due to reduced volumetric ow and the introduction of the recycle loop.165 which can in turn lead to higher concentrations of SO3. the overall emission rate of SO2 (mg MJ1) is lower158.156 Studies of possible implementation of the OTMs have found that their use limits the drop in overall net plant efficiency by 5. Primary measures that reduce NOx formation in the furnace by modifying the combustion environment (i. where the membrane temperature is maintained by preheating the air. which can result in enhanced production of NOx from fuel-N if the burner is not suitably designed and operated. The amount of NOx emitted per unit of energy generated can be reduced to around a third that of airring. very high concentrations of oxygen are oen present locally in oxy-coal ames. the development of deNOx in CO2 compression and purication processes via conversion of NO to NO2 and removal by absorption in condensate is in progress. increasing the driving force by removing the permeating oxygen and maintaining the necessary operating temperature. Pilot scale experimental trials by ENEL have shown that pressurised systems146. In the four-end concept.152 hollow bre153 and at. including aluminium used in CO2 compression units.8Fe0. Typical membrane materials like Ba0.e. wall soot blowing.151 monolithic. The pressurised oxyfuel system is achieved by pre-compressing oxygen in the ASU which leads to high pressure combustion ue gases and a reduction in the work duty of the CO2 compression unit.154 Vente et al.166.161 have concluded that fuel-N conversion to NO in O2/CO2 is lower than in O2/CO2.167 than air ring due to the increased conversion of SO2 to other species throughout the process. because NOx in the recycled gas can be reburned by contact with ame-generated hydrocarbons. The membrane in the fourend concept will have direct contact with ue gas. the driving potential is sustained by applying vacuum to the permeate side or by an increased feed pressure. Sensitivity studies by Massachusetts Institute of Technology have determined that maximum efficiency can be achieved in the vicinity of 10 bar combustor operating pressure.. fuel staging and ue gas recirculation) are believed to be sufficient for oxyfuel combustion but this will depend on future legislation for CO2 emission and storage. Membranes for oxygen production can be operated with a three-end or four-end design.150 To conduct oxygen. as nitrogen from the air is largely eliminated from the process by substitution with RFG.157–159 Recent experimental investigations of NOx formation during oxyfuel combustion of pulverised coal160. The emission of mercury in oxy-coal combustion is a corrosion concern because it forms an amalgam with a number of metals. which act as a reducing agent to produce N-volatiles.171 tests in a 30 MW pilot scale facility of Babcock and Wilcox showed mercury concentration to increase Energy Environ. Sci. Different membrane module types are being investigated: tubular. Downloaded on 05/11/2015 11:56:07. Elevated concentrations of SOx present serious implications for CCS technologies.and fourend concepts will have implications for the types of materials that can be considered for membranes.170. a sweep stream of RFG is applied on the low pressure side of the membrane. the amount of compression work between the ASU and compression unit is reduced in comparison to conventional atmospheric oxyfuel operation. Overall. allowing the possibility of burning cheaper coals and reducing the size of components. the temperature of the OTM must be maintained above 800 C and an oxygen partial pressure gradient must be applied across the membrane.3 Pollutant emission and removal An operational benet of oxyfuel combustion is the reduction of NOx and SOx emissions. air-staging.163 Additionally. While the change of environment from N2/O2 to CO2/O2 may have little effect on the ratio of Hg0 to Hg2+.165 Development of optimal strategies for SOx mitigation and control requires techno-economic evaluation. Oxyfuel combustion offers highly reduced NOx emissions.169 Elemental mercury can speciate to the oxidised form (Hg2+) or particulate bound forms HgP during post-combustion quenching.5Sr0. 2014. However. sulphur scrubbing prior to recycle or compression and removal during compression. In the three-end concept.162 The reduction in volume throughput of oxyfuel combustion also leads to higher concentration of NOx in the system. including boiler and pipeline corrosion.2% for fourend concept and 5. thermal and prompt-NOx formation rates are highly reduced.148 Further studies have been conducted to reduce the energy consumption of the ASU by investigating the use of hightemperature oxygen transport membrane (OTM) technology for oxygen production as an alternative to conventional cryogenic distillation methods.147 have increased heat transfer rates in the Heat Recovery Steam Generator (HRSG).View Article Online Published on 13 September 2013.155 compared the different module designs and concluded that tubular systems are the optimal choice for all considered conditions. the three-end concept will be more technically viable in the near term because no membrane material has yet been identied that can withstand contact with ue gas. 130–189 | 141 . which can make integration in coal powered plants complicated because coal derived ue gas contains corruptive components such as particles and corrosive acid species. limestone injection. Although the four-end concept is preferable due to the higher plant efficiency. consisting of ammonia and cyanide species that may subsequently produce NOx or N2 depending on the conditions.5Co0. Moreover.149.168 Mitigation and control strategies for SOx include the use of low sulphur and/or high calcium coals. which allows many different materials to be employed. Review enthalpy in the ue gases lead to higher thermal energy recovery from the water in the ue gases.2O3x (BSCF) and Li2NiO4 that have high permeation rates at the conditions of interest have been found to be unsuitable for four-end operation due to chemical instability aer contact with ue gas components. 7. transported by refrigerated truck183 to several storage and industrial sites.181 Next generation technologies will include co-ring with biomass. more sophisticated methods such as LES should replace classical turbulence models for CFD. The 30 MWth Lacq project by Total in France uses natural gas as fuel and commenced in 2009. The technology is based on the “lead chamber process”. Physical effects (heat capacity and mass transfer) and Arrhenius parameters for homogeneous and heterogeneous reactions must be adapted for accurate prediction of char burnout and the transition between combustion regimes. More investigations of the release and distribution of these substances under oxyfuel conditions are required.182 designed for 10 tpd of CO2. Sci. very signicant improvements in materials and system design are needed. The CO2 is injected down to a depth of 4500 m into a depleted gas eld. NOx and mercury during compression using their “Sour Gas Compression” technology. As computational resources increase. Cd. the radiative transfer equation must be solved and coupled with a radiative properties model that species the gaseous and particle properties. CFD modelling for oxyfuel combustion relies on sub-models that were initially developed for air-ring conditions.181 Nevertheless. Se.185 The Callide Oxyfuel project is the rst demonstration of retrot to an existing coal-red boiler with electricity generation supplied to the open market and includes on-line coal milling. in addition to proving the commercial viability of the technology. became the world’s rst full chain oxyfuel pilot demonstration. and are spread out between several countries. Vattenfall’s Schwartze Pumpe 30 MWth plant in Eastern Germany.View Article Online Published on 13 September 2013. Energy & Environmental Science in oxy-coal combustion. This could lead to drastic plant size reductions. polyaromatic hydrocarbons.g. Reynolds Averaged Navier Stokes (RANS) models are considered an acceptable compromise between accuracy and computational cost. Radiative heat transfer in oxyfuel combustion is very different than air combustion due to altered gas emission and absorption. Vattenfall’s 250 MWth J¨ aenschwalde plant in Germany will also generate electricity for the open market and has an operational aim of 2015. Downloaded on 05/11/2015 11:56:07. the increase in Hg oxidation may be explained by increased chlorine concentration in oxyfuel combustion. Strategies to control Hg emissions include injection of activated carbon sorbents or forcing oxidation to water soluble Hg2+ forms to then be removed by conventional FGD scrubbing. dioxins and other chlorinated compounds are currently available. 2014. Little information on the behaviour under oxyfuel conditions of other pollutants such as particulates. efficiency increases and cost reductions. sharing of CO2 transport pipelines and boiler designs optimised for higher O2 concentration.. some of the models require further modications and validation in order to be reliably applied in the CO2 rich environment. 7. At present.5 Recent trials and developments Pilot-scale and industrial demonstration projects for oxyfuel combustion are crucial for verifying observations and theories from laboratory and bench-scale. CanmetENERGY are working on oxyfuel systems that aim to minimise or eliminate the RFG. Sweden176 and Imperial College London177). This was the rst time an oxyfuel project has been coupled to pipeline transport for geosequestration. Technologies which combust coal in a mixture of oxygen and steam/or water. Large Eddy Simulations (LES) are more computationally intensive and have recently been applied to oxyfuel combustion. Char oxidation and burnout is inuenced by the high concentrations of CO2 and H2O in oxyfuel combustion. known as hydroxy-fuel combustion This journal is © The Royal Society of Chemistry 2014 . Reduced gas-phase chemical kinetic mechanisms which can be adopted within CFD codes at acceptable levels of computational cost require development for CO2 rich environments. all operated pilot-scale and demonstration projects have been #100 MWth in size. The Lacq project does not include any inerts-removal step.178 LES was found to be capable of capturing the intermittency effects of the coal ame and the importance of gas radiative properties was also demonstrated in the calculations. The majority of projects have focused on the CO2 capture process only. volatile organic compounds (VOCs). heat transfer and chemical reactions in combustion can be investigated. etc. Further pilot-scale work in this area has been performed by CANMET175 and at the laboratory scale (e. This project aims to convert an oil-red process into an oxycoal-red utility at the 200 MWe scale. While signicant progress has been made in adapting the CFD sub-models for application to oxyfuel conditions.184 so CO2 is transported at 92% purity and 27 bar along an existing pipeline through a populated area. 4. As. other trace metals (Pb.). Mercury will dissolve and react in the nitric acid formed as a condensate.179 Utility boilers can be modelled in 3D and the impact of changing various design parameters on uid ow.4 Computational uid dynamics modelling Oxyfuel combustion presents numerous opportunities and challenges for numerical modelling. Future commercial demonstration-scale oxyfuel plants have recently been announced. Until now. 130–189 Review Accurate turbulence models are required since turbulence has important effects on mixing. 4. The dominant mode of heat transfer in both air and oxyfuel combustion is radiation. kinetics and heat transfer with greater signicance under oxyfuel conditions. Efforts have recently been made to improve the models for gaseous radiative properties by making them applicable to oxyfuel combustion modelling. Chalmers University.180 142 | Energy Environ. The largest currently operating integrated CCS chain involving oxyfuel combustion is the Callide 30 MWe oxyfuel project which began in 2011 in Australia.173 The process relies on the oxidation of NO to NO2 to convert SO2 to H2SO4174 in the presence of water. The FutureGen 2 Merediosa project has been announced. Further investigations are required to determine the kinetics at higher pressure. To calculate radiation within a utility boiler.172 While the increase in Hg concentration is due to the removal of diluent nitrogen. which began in 2008.178 Extensive use of Computational Fluid Dynamics (CFD) modelling tools for the scale-up and advanced design of oxy-coal combustion facilities is expected. without linking to CO2 transport and storage. To achieve this objective. Air Products have developed the possibility of co-removal of SOx. Sci. This means that unlike PC systems. in oxyring. In this technology. 5. A key difference between air.2 Gas and other emissions from oxyfuel CFBC Air-red CFBC technology normally produces low emissions of SO2 on addition of limestone. are also being investigated. Oxyfuel CFBC Until recently. and oxyfuel CFBC is being considered in many other industrially important countries such as Russia191 and Australia. CanmetENERGY in Canada currently has one of the most detailed and well-reported programs. no fundamental technical barriers have been encountered with the operation of pilot and demonstration scale test facilities. CFBC can be regarded as a low SO2 emissions technology. without ue gas recycle. so water or steam will act as a temperature moderator. However.198 investigated the effect of operating parameters on NO formation using a 50 kWth oxy-red CFB. low NOx due to its low operating temperatures. and also low emissions of heavy metals. 130–189 | 143 . This lower volume of ue gas means that emissions are best This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science expressed in terms of mg MJ1 or some similar unit. However.. however.g. to avoid misleading comparisons with gas emissions from air-red units where pollutants are diluted with N2 from the air. it was not until the last decade that the oxyfuel FBC technology received serious attention. anhydrite). in which gas velocities are of the order of 4 to 8 m s1. For utility applications.and oxy-ring is that unless the CFBC is operated above about 870 C. Downloaded on 05/11/2015 11:56:07. As discussed above.187 with larger (550 MWe units) currently being built. thus ensuring high heat transfer rates. less than 1000 C). Alstom190 and Foster Wheeler. and this technology is available in the supercritical mode at sizes of up to 460 MWe. instead of recycling ue gas to achieve the necessary gas velocity and solid circulation rate in terms of heat transfer requirement.5). it is reasonable to assume that if a technology such as oxyfuel CFBC has inherently low emissions then this must represent an advantage. began to carry out pilot-scale test work and other studies to see if it could be developed as commercial CFBC boiler technology with CO2 capture. Similarly. which would allow oxyfuel CFBCs of any given thermal output to be built. with more planned in the future (see Section 4. While this technology was explored 35 years ago189 in its bubbling bed mode (uidising velocities 1 to 2.1 Pilot plant studies Although functioning pilot plant units are still limited in number (as indicated in Table 3). the CaO/CaCO3 equilibrium indicates that capture will be with CaCO3 directly (so-called direct sulphation). and also found that NO production with 21% O2/79% CO2 was lower than for the air-red case. lower levels of ue gas recirculation are possible. the fuels are burned in a turbulent bed of an inert material. and/or using bottled gases to supply a suitable combustion gas.193 To date. due to the much higher partial pressures of CO2 in an oxyfuel CFBC. some technical uncertainties remain. RGF is not used. The successes of demonstration projects will provide practical information and experience needed to push forward oxyfuel technology to commercial realisation. 2014. such as those related to ue gas cleaning. the obvious route for oxyfuel combustion was via conventional pulverised coal-red (PC) boiler technology as discussed above. called circulating uidised bed combustion (CFBC) is employed.197 At the moment it is far from clear how pure ue gases should be to allow the least-cost production of CO2 for piping and sequestration.188 CFBC is now a widely used technology for the power industry for difficult fuels (e. Duan et al.192 Also. Furthermore if sulphur capture is required. and good solid mixing. Successful runs on the 75 kWth unit were achieved and reported in 2007194 and much of the emissions data195 discussed below come from this unit.5%. A series of trials194. with fuel nitrogen conversions down to 1. ue gases must be recycled in order to keep combustion temperatures to manageable levels (in the case of CFBC. where perhaps 70–80% of the ue gas must be recycled. limestone can be added to the bed. More recently. In this technology. ash or moisture content or for almost any waste material). due to its ability to use limestone to trap SO2 in situ. 5. the technology will lead to reduction in equipment size and will utilise novel turbomachinery that can generate power from the expansion of steam–gas mixtures. based on results from two pilot plants which are capable of being operated in oxyfuel mode. recently oxy-red uidised bed combustion (FBC) has also become increasingly important as a potential technology offering both fuel exibility and the possibility of ring or co-ring biomass with CO2 capture. and thus improve plant cost savings. studies are being undertaken in numerous countries. the hot solids which are an integral part of CFBC technology can also be used for extra heat transfer and steam production.8 MWth unit. 5. The global reactions which describe sulphur capture in a CFBC are given below: CaCO3 + SO2 + 1/2O2 ¼ CaSO4 + CO2 (7) CaCO3 ¼ CaO + CO2 (8) CaO + SO2 + 1/2O2 ¼ CaSO4 (9) Energy Environ. these can potentially be 30 or 40% smaller than the equivalent air-red units. ensuring SO2 is removed in solid form (CaSO4. 7.186 As oxyfuel combustion approaches the commercial demonstration stage of development. most test work has been done at small scale (in the <100 kW range). there is now an international workshop on oxyfuel FBC.195 indicated that fuel nitrogen conversions were oen about half that seen from air-red trials. with full ue gas recycle: a nominal 75 kWth unit and a larger 0. when two large boiler companies. low volatiles content or high sulphur. However.View Article Online Review Published on 13 September 2013. rather than with CaO produced from the rapid calcination of limestone at temperatures above 790 C. either in the primary reaction loop and/or in external uid bed heat exchangers.5 m s1). and there is already one large European oxyfuel PC demonstration plant. a high velocity version of FBC. unlike oxyred PC units. which is held annually.5 to 3. which can be landlled. low emissions of organic species in the form of unburned hydrocarbons.196. . with ue gas recycle Support of national Canadian program on oxy-fuel CFB Unit did not employ ue gas recycle. most trace elements tended to report to the overhead streams (i.201 albeit that the bituminous coal used contains only 0. Unfortunately.8 MWth CFBC. CanmetENERGY has also examined co-ring of up to 80% wood with a bituminous coal and found that trace elements in the ue gas are negligible. but note again that SO3 concentrations do not appear to be noticeably affected by the amount of limestone addition. By contrast. 7).192) Location Size Purpose Additional information Alstom. but more so for air ring. Windsor. however. USA 100 kWth 0.195 has suggested that limestone utilisations are comparable or lower for oxyfuel CFBC combustion. Interestingly. Sci. but R&D on the unit. in this work the bulk of the Hg was found in the elemental form.33 MWth Metso Power. Alstom also operates a number of smaller facilities including a 400 bench-scale FBC (see [Marion et al.5 MPa Typically.572] for an overview of the company’s program in oxyfuel FBC) Foster Wheeler used VTT. at the levels present when burning any hydrocarbon fuel. Spain University of Utah.View Article Online Energy & Environmental Science Published on 13 September 2013. VTT and Lappeenranta University of Technology. represents the beginning of the company’s development of oxyfuel FBC technology. enhances the sulphation in both the air ring and oxyfuel case. Table 3 Review List of pilot plant oxyfuel FBC facilities (modified from Wall et al.1 MWth Provided design and operational data for oxyfuel CFB. from preliminary research done by CanmetENERGY on its 0. Finland along with CanmetENERGY facilities to test numerous fuels and limestones573 as a prelude to their demonstration plant at CIUDEN199.56% sulphur. particularly at the base of the bed. USA 3 MWth Feasibly studies on O2 fuel FBC technology Foster Wheeler. China Zhejiang University. Downloaded on 05/11/2015 11:56:07. Font et al.199 CanmetENERGY work200 has suggested that high-temperature steam. Finland 4 MWth Bubbling FBC used to generate fundamental data Generation of fundamental knowledge Developing commercial technology Czestochowa University of Technology. Poland ICB-CSIC Spain 0. with fundamental studies performed by Chalmers University. The issue of SO3 emissions.1 and 0.e. insufficient studies have been carried out to determine this issue unequivocally. and potentially high oxygen concentrations.5% S and an Illinois coal with 4% S).194. CT. there are still rather limited data. As expected.207 0. However.201 On the question of Hg emissions. given its potential to cause corrosion. might also enhance its formation. They also point out that the presence of particles may provide more opportunities for SO3 formation via catalytic processes. The work of Jia et al. 2014.7–11. Canada 0. Here the pH of the leachate for the bed ash was in the range of 10. a Utah coal with 0.203 have investigated the fate of Hg and other trace elements employing a 90 kWth oxy-red bubbling FBC. which began in 2001. Ahn et al. and for the cyclone y ash even lower (pH ¼ 8). to date.1. is something which is also of interest for oxyfuel systems. Recently. China 100 kWth 30 kWth North China Electric Power University NA Bubbling bed facility used for generation of fundamental data Generation of fundamental data Bubbling bed used to generate fundamental knowledge Batch pressurised bubbling bed facility (using 10 g of fuel) capable of operating up to 4. although recent tests from the 30 MWth CIUDEN demonstration unit have also suggested somewhat lower limestone utilisation. Utah.1 MWth Generation of fundamental data 3 kWth Southeast University.8 MWth CIRCE.202 144 | Energy Environ. 130–189 A co-operation between Metso and Fortum. for two reasons: the use of recycled ue gases will likely increase SO3 levels. cyclone and y ash). they appear only to have examined SO3 levels for the Utah coal.2% S. University of Zaragoza. Finland CanmetENERGY. levels do not seem excessive at 2 ppmv or less. so that sulphation is better or comparable in air ring to oxyfuel combustion (Fig. Hg emissions were This journal is © The Royal Society of Chemistry 2014 .5 MW pilot-scale PC combustor and a 330 kW pilot-scale CFB test facility (using a PRB coal with 0. 7. in some recent work done at CanmetENERGY on a bituminous coal. for which they conclude that SO3 levels are similar for both air and oxy-ring under their conditions. Sweden574 Unit has also been used to support Foster Wheeler’s program have also recently examined SO3 concentrations for a 1. limestone conversion in a CFBC is relatively low with the 30–45% utilisation being regarded as acceptable. There is currently a dearth of information on this subject for oxy-FBC systems. If CLC were to be used for power production with gaseous fuels. (2n + m)MexOy + CnH2m / (2n + m)MexOy1 + mH2O + nCO2 (10) The exit gas stream from the fuel reactor contains CO2 and H2O.e. no further information appears to be available in the open literature. The fuel is introduced in the fuel reactor.199. The fuel and the metal oxide react according to: Fig. Foster Wheeler is now working with the power company ENDESA on the development of a 300 MWe supercritical Flexi-Burn® CFBC.209. The reduced metal oxide. Fig. rather than a more efficient combined cycle. as way to produce pure CO2 from fossil fuels. Finally. which contains a metal oxide.204 5. Downloaded on 05/11/2015 11:56:07.206 Foster Wheeler also believes that it could offer such technology at the 600–800 MWe size with 600 C steam temperature. 8 Chemical-looping combustion. 130–189 | 145 . see Fig. where the oxygen is in direct contact with the fuel. MexOy/MexOy1 denotes recirculating oxygen carrier material. using two interconnected uidised beds. Potentially promising technologies. it must be noted that Alstom has also announced its intention of carrying out a 100 MWe oxyfuel CFB demonstration. CLC would limit the efficiency of the underlying thermodynamic cycle to that of a steam cycle. Demonstration tests are currently underway at the 30 MWth CIUDEN pilot CFB demonstration unit. this is normally not an issue.. which will provide a full experimental CCS platform for the demonstration and validation of exible air/oxyfuel CFB combustion.1 Introduction Chemical-looping combustion has emerged as an attractive option for carbon dioxide capture because CO2 is inherently separated from the other ue gas components. is transferred to the air reactor where it is oxidised. 2014. Foster Wheeler was also the rst to commercialise supercritical CFBC technology (Lagisza power plant. and it is highly probable that it will also be available as a competitive CCS technology along with oxyfuel PC technology before the end of the decade. i. The predicted CO2 capture for this technology is 90% of emissions and it is anticipated that it could be available by 2020. and thus no energy is expended for the gas separation and no gas separation equipment is needed. Review Energy & Environmental Science unused O2. reaction (10) is oen endothermic. Energy Environ. while reaction (11) is exothermic. However. 0.3 Larger-scale tests and industrial plans Foster Wheeler commissioned 8 months of trials at CanmetENERGY and these trials demonstrated excellent control on CO2 levels and combustion conditions. and not pressurised. Sci. proposed the use of chemical-looping combustion for climate mitigation and also started laboratory research on oxygen-carrier materials.205 Overall performance was excellent. CLC was rst introduced by Lewis et al. Chemical-looping combustion 6. Poland) and with this technology as the basis.8 mg m3 or less with about 80% of the Hg present in an oxidised form. and a stream of CO2 is obtained when H2O is condensed. The metal oxides used for the oxygen transfer are called oxygen carriers. reaction (11): MexOy1 + 1/2O2 / MexOy (11) The air. or if solid fuels are used. 7.View Article Online Published on 13 September 2013.207 An interesting feature of this unit is that it uses NH3 injection into the cyclone to help maintain NOx at 120 mg Nm3. the efficiency of the baseline technology must also be taken into account. The total amount of heat evolved from reaction (10) and (11) is the same as for normal combustion. Depending on the metal oxide and fuel used. will also be discussed below.211 6.208 It appears that oxy-red CFBC technology is making major strides to enter the commercial arena. which oxidises the metal oxide. although at the time of writing. However. Ishida et al. MexOy. such as chemical looping reforming. N2 and This journal is © The Royal Society of Chemistry 2014 Fig. 7 Sulphation conversion profiles under oxy-fired conditions for varied concentrations of H2O (with air-fired profiles overlaid).210 Much later. The CLC system is composed of two reactors. The reactor system is normally made up by two interconnected uidised beds. 8. 9. with the oxygen carrier in the form of particles being circulated between the two beds. where the aim is to produce steam/heat or hydrogen. which is a very positive sign for the development of the technology. an air and a fuel reactor. MexOy1. produces a ue gas containing only N2 and some unused O2. which avoid this issue. View Article Online Energy & Environmental Science Review means that CLC with solid fuels will require a different design of the fuel reactor, as well as oxygen carriers with other properties. The following key issues have been identied in relation to fuel reactor performance: solid fuel conversion, gas conversion and CO2 capture. Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. 6.3 Fig. 9 CLC process, example with two interconnected fluidised reactors. (1) Air reactor and riser, (2) cyclone, (3) fuel reactor, (4) loop seals. Ishida also introduced the name of the process, chemicallooping combustion.212 In 2001, a design based on the circulating uidised-bed principle was presented, see Fig. 9, investigating the critical design parameters of a system such as the solids inventory and recirculation rate of oxygen carriers between the reactors and identifying the relationship between these and the oxygen carrier properties.213 6.2 Applications Most of the work so far has been focused on gaseous fuels. Gaseous fuels can be used directly as the uidising medium of the fuel reactor. Important gaseous fuels, e.g. natural gas and renery gas, contain large amounts of methane. Thus, oxygen carrier development has had signicant focus on oxygen carrier materials with high reactivity towards methane. Liquid fuels would also be a possible fuel, but except for the operation involving kerosene in a 300 W unit,214,215 little operational experience is presently available with liquid fuels. Different liquid fuels including heavy fuel oil have been studied in uidised-bed batch reactor tests.216 The pioneering work of Lewis et al.209,210 utilised copper and iron oxides. Fiy years later, new studies emerged,217–219 revisiting the same oxides. Soon aer, Leion et al. investigated different fuels and oxygen carriers in a laboratory uidised bed,220–222 and today there are a number of publications of laboratory work with solid fuels, as well as from actual operation in smaller pilots.223,224 When using solid fuels, the reaction between the oxygencarrier and the char remaining aer volatiles release is not direct, but involves an intermediate gasication step. This 146 | Energy Environ. Sci., 2014, 7, 130–189 Using CLC for hydrogen production with CO2 capture The chemical-looping technology can also be adapted for the production of hydrogen with inherent CO2 capture. Chemicallooping processes for hydrogen production from gas include, (i) autothermal chemical-looping reforming, (ii) chemicallooping steam reforming, and (iii) chemical-looping with water-splitting. Autothermal chemical-looping reforming, CLR-a, involves utilising chemical-looping for partial oxidation to form a syngas. That, aer water–gas shiing, can be separated into CO2 and H2.225–228 Chemical-looping steam reforming, CLR-s, or chemicallooping combustion with steam reforming, is a marriage between conventional steam reforming and CLC.229 Just as in commercial steam reforming, the reactions take place inside tubes using suitable catalysts and at elevated pressures. The steam reforming tubes are placed in a separate uidised-bed heat exchanger. Hence, the reformer tubes are not heated by direct ring but by oxygen carrier particles, which means extracting the heat generated from the CLC process. The feed gas to the fuel reactor is the offgas from the steam reforming process, which is a gas mixture of CH4, CO2, CO and H2. The CLR-s process has a number of important advantages: (i) only one gaseous component, i.e. H2, needs to be separated, unlike the CLR-a process, where two essentially pure streams of CO2 and H2 are needed, (ii) the chemical-looping can take place at atmospheric pressure, while the reforming can occur at high pressure, (iii) compared to the gas boilers used in conventional steam reforming, the temperature around the tubes is considerably lower and more uniform. The lower temperature means that a greater fraction of the combustion heat is used for steam reforming, with the consequence that the reforming efficiency is increased. This may well be the only CO2 capture technology which results in increased efficiency (if the efficiency loss of CO2 compression is not included). Chemical-looping with water-splitting, also known as OneStep Decarbonisation, uses three reactors.230 The process requires an oxygen carrier which is reduced in steps through different oxidation states, e.g. Fe2O3 > Fe3O4 > FeO. In the fuel reactor, the fuel and oxygen carrier needs to move countercurrently. In the top, Fe2O3 is reduced to Fe3O4, while accomplishing complete combustion of the fuel, and in the bottom, Fe3O4 is further reduced to FeO. Then, in the water splitting reactor, the FeO is oxidised to Fe3O4 by steam, yielding hydrogen. Finally the material is led to the air reactor where it is oxidised back to Fe2O3. Note that two changes in oxidation state are needed. Fe2O3 to Fe3O4 is needed to fully oxidise the fuel, while FeO to Fe3O4 is needed for water splitting. The process elegantly avoids any gas separation in the hydrogen production but at the price of an added complexity of the reactor system. This journal is © The Royal Society of Chemistry 2014 View Article Online Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. Review There is also work with chemical-looping of solid fuels directed towards hydrogen production, rather than complete combustion, which is similar to the chemical-looping reforming and water-splitting processes proposed for gaseous fuels. A chemical-looping process for the production of syngas using solid fuels and two interconnected uidised beds was patented more than 60 years ago.225 Some more recent processes involve using lime to enhance fuel conversion to H2 by in situ CO2 removal, e.g. the Alstom Hybrid Combustion–Gasication Process and the GE Fuel-Flexible Process.231 With respect to water-splitting, it should be mentioned that going back 80–90 years, the main process for hydrogen production was the socalled steam-iron process. In this process, iron oxide was reduced by coal to iron, and the iron was then reacted with steam to form hydrogen.231 Related processes that are concerned with the direct production of hydrogen through watersplitting using Fe/FeO being studied today are the Syngas Chemical-Looping process (SCL) and the coal direct chemicallooping process.231 6.4 Oxygen carrier materials More than 900 different oxygen carrier materials have been studied in the laboratory,232 and there are several reviews covering oxygen carrier materials,223,232,233 and discussing important criteria and the required thermodynamic properties.234 The rst phase of oxygen carrier development focussed mainly on four metal oxides: Ni, Fe, Mn and Cu. However, the development over the last few years has been more diversied; there has been more work on combined metal oxides, on low-cost materials for use with solid fuels, and on materials releasing oxygen, i.e. CLOU materials (see the following section). Combined metal oxides, i.e. where two or more oxides are combined not only physically, but also chemically, produce new oxides, for example, Cu0.95Fe1.05AlO4, Co0.5Ni0.5FeAlO4, CoFeAlO4, CuFeGaO4, NiFeAlO4.235 Some of these materials have the perovskite structure, e.g. La1xSrxFe1yCoyO3d, and Sr(Mn1xNix)O3.236,237 Other types of oxide that should be mentioned are combined Mn oxides with partial CLOU properties, i.e. with the ability to release some oxygen. This includes Mn combined with Ca, Mg, Ni and Fe.238–240 Many of these combined materials are promising, but fewer have been successfully tested during actual operation. An exception is CaMn0.875Ti0.125O3.241 Another is ilmenite, FeTiO3, a naturally occurring low-cost combined oxide commonly used with solid fuels. Low-cost materials have been investigated mainly for use with solid fuels, these studies include iron ore,242–244 manganese ore,245 ilmenite, CaSO4/CaS,246–253 industrial waste materials,254,255 as well as comparisons of materials of different sources.256,257 Most of the studies have used ilmenite,258–262 because it is a cheap ore, has a reasonably high reactivity towards syngas and has shown good uidisation behaviour. Most materials studied have only been investigated in laboratory, but a signicant number of different materials have actually been used in continuous operation in CLC pilots. These include oxides of nickel, copper, iron, manganese and cobalt, as well as natural minerals like ilmenite, iron ore and manganese ore. This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science 6.5 Chemical-looping with oxygen uncoupling (CLOU) Chemical-Looping with Oxygen Uncoupling (CLOU) is closely related to chemical-looping combustion but differs from CLC through the spontaneous release of oxygen in the fuel reactor. For instance, the CuO/Cu2O system has an equilibrium oxygen partial pressure of 0.02 bar at a temperature of 913 C. This means that, at this temperature, the O2 concentration could be reduced down to a minimum of 2% in the air reactor, while oxygen could be released up to maximum 2% in the fuel reactor. As the presence of fuel in the fuel reactor will consume oxygen released, a very rapid release of oxygen is possible. CLOU using CuO has been shown to work not only in laboratory batch uidised-bed tests with CuO and solid fuel,263,264 but also in continuous operation with solid fuel.265 Also, combined manganese oxides have the ability to release oxygen240 and successful operation with calcium manganates has been reported.241 6.6 Fluidised bed reactor system for CLC In order to investigate uidised systems for CLC, a number of studies have utilised cold-ow modelling to identify stable and suitable operating conditions for various designs.266–272 Actual operation in 12 CLC units of sizes 0.3 to 140 kW involving 29 oxygen-carrier materials was reported by Lyngfelt.273 The units are presented in Table 4, including eight additional units. Thus, more than 4800 h of operation in 20 units of sizes 0.5 to 140 kW, using a number of different oxygen-carriers and fuels have been accomplished. This includes more than 600 h in seven units using solid fuels. The successful operation in a number of small units with different designs, different fuels, and different oxygen carriers, clearly demonstrates that the process works and is viable, and that there are suitable oxygen-carrier materials for this new combustion technology. 6.7 Modelling For gaseous fuels, the main performance criterion is fuel conversion in the fuel reactor, and the work primarily involves estimations of the required solids inventory to gain a given conversion to CO2, and its comparison to actual achievements.223,274–277 For solid fuels, the performance is more complex, and normally three performance criteria are used, (i) solid fuel conversion, (ii) gas conversion and (iii) CO2 capture efficiency. These can essentially be modelled separately (as seen in publications available).278–282 6.8 Conclusions for CLC Although more development work is needed, it should be pointed out that the CLC technology provides unique advantages for avoiding the large costs and energy penalties inherent in gas separation. In the case of gaseous fuels, the following conclusions can be made: The technology has been successfully demonstrated in a number of smaller pilots and the technology should be ready to scale up to 1 or 10 MW size. Energy Environ. Sci., 2014, 7, 130–189 | 147 View Article Online Energy & Environmental Science Review Published on 13 September 2013. Downloaded on 05/11/2015 11:56:07. Table 4 Testing in chemical-looping combustorsa Location Unit Oxides tested Time Fuel\references Year Chalmers KIER CSIC Chalmers 10 kW 50 kW 10 kW 0.3 kW 1410 28 120 810 Nat. gas\575–578 Nat. gas\579,580 Nat. gas\581,582 Nat. gas, syngas\227,241,583–591 2004 2004 2006 2006 Chalmers CSIC KAIST Vienna UT Alstom Nanjing KIER Nanjing IFP-Lyon Stuttgart Xi’an Jiaotong CSIC Chalmers Chalmers Hamburg Ohio 10 kW-SF 0.5 kW 1 kW 140 kW 15 kW 10 kW-SF 50 kW 1 kW-SF 10 kW-GSF 10 kW 10 kW-Pr 0.5 kW-SF 0.3 kW-LF 100 kW-SF 25 kW-SF 25 kW-SF NiO, Fe2O3 NiO, CoO CuO, NiO NiO, Mn3O4, Fe2O3, ilmenite, CaMnO3 Ilmenite, manganese ore CuO, NiO, Fe2O3 NiO + Fe2O3 Ilmenite, NiO NiO NiO, Fe2O3 NiO, CoO Fe2O3 (ore) NiO Ilmenite CuO/Fe2O3 Ilmenite, CuO, Fe2O3 NiO, Mn3O4, CuO Ilmenite Ilmenite Fe2O3 149 820 ? 390 100 230 300 >10 >90 ? 15 164 116 24 21 72 Coal, petcoke\245,259,592–595 Nat. gas\228,254,596–606 CH4\607 Nat. gas, CO, H2\262,608–617 Nat. gas\4 Coal, biom.\618–621 Nat. gas, syngas\622 Coal, biomass\244,623 CH4, coal, syngas\624,625 Syngas\261 Coke oven gas\626 Coal\260,265,627,628 Kerosene\214,215 Coal\629–632 Coal\633 Coal\634 2008 2009 2009 2009 2009 2009 2010 2010 2010 2010 2010 2011 2011 2012 2012 2012 a SF – solid fuel, GSF – gaseous & solid fuel, Pr – pressurised, LF – liquid fuel. The presently studied technology, i.e. systems that operate under atmospheric conditions and temperatures of 800–950 C, would have signicantly lower efficiency in power production as compared to natural gas combined cycle (NGCC) plants. CLC for higher pressures and temperatures need signicant development efforts. However, there are a number of applications where gaseous fuel CLC could be used for steam/heat production. The following conclusion can be made for CLC with solid fuels: The technology is similar to established combustion of coal in circulating uidised beds. There is a unique potential for dramatic reduction in cost and energy penalty for CO2 capture. CLC operation with low-cost mineral ilmenite works well, but to reach high performance, additional development is needed, either with regards to reactor system or the oxygen carrier material used. Oxygen carrier materials other than ilmenite could provide signicant improvement of performance, but it is not clear if are they available at reasonable costs. The following options to have a complete conversion of the gas to CO2/H2O in the fuel reactor are available: (i) oxygen polishing, (ii) separation/recycling of unconverted gas (iii) using two fuel reactors in series and (iv) CLOU oxygen carriers. For scale-up, a more detailed understanding of the processes in the fuel reactor is needed to design and optimise the fuel reactor system, in order to assess how the performance will be affected by the properties of the oxygen carrier and the reactor design. The optimisation of the fuel reactor system will primarily need to consider three costs, i.e. costs for oxygen carrier, costs 148 | Energy Environ. Sci., 2014, 7, 130–189 for the fuel reactor system, and costs downstream of the fuel reactor to accommodate for incomplete conversion, e.g. oxygen polishing. Consequently, a good understanding of these costs is needed to nd the optimal solution and realise the great potential of this technology. 7. Calcium looping, CaL Calcium looping is a family of CO2 capture technologies that use CaO as a regenerable sorbent of CO2: CaO(s) + CO2(g) $ CaCO3(s), DH298K ¼ 178.8 kJ mol1 (12) Both the carbonation and calcination reactions are carried out at high temperatures (650–700 C and 900 C, respectively), allowing for efficient heat recovery in the process or steam cycle of a power generation system. The technology has attracted, in the last 10 years, a great deal of attention, and several comprehensive reviews have been recently published.283–287 Only the main aspects and newest developments are discussed in this section. The use of this chemical loop was rst attempted in the 19th century as it was noted that gasication gases would have a higher heating power when coal was gasied in the presence of CaO. This idea was exploited in the acceptor gasication process, which tested the principle in a continuous pilot rig using an interconnected uidised bed coal gasier and a combustor operated at high pressure.288 Other hydrogen generation processes have been investigated from the 90s, focusing on the sorption enhanced reforming principle.289 The rst application of Ca-looping as a post-combustion CO2 capture process was patented by Hirama et al.290 They also This journal is © The Royal Society of Chemistry 2014 299. Published on 13 September 2013. 7. 130–189 | 149 .297. sulphation conversion (XCaSO4) and total sorbent utilisation (sum of both) measured on solid samples from a long duration experiment in La Pereda pilot plant.301 Several projects have been running in order to prove experimentally the concept of post-combustion CaL using interconnected carbonator and calciner reactors.303 This test facility was also used to test the principle of low-temperature combustion of biomass (700 C) for in situ CO2 capture.35 m height) located at Darmstadt University. Experimental campaigns using propane and pulverised coal as fuels to supply the heat for sorbent calcination provided CO2 capture efficiencies above 90%.4 m height) and a bubbling uidised-bed calciner. A third subsection reviews recent developments on sorbent performance issues that are common for both process routes. or other large scale uses of CaO. but only recently detailed specic process proposals and experimental investigations have been reported.292–295 The calcination of the fresh make up ow of limestone can take up to 3–10% of the total energy input to the Ca looping system.1 m and can be operated at up to 1000 C at atmospheric pressure. 11 shows the evolution of the CO2 carrying capacity (Xave).. which were designed to accommodate a wide range of solid looping and make-up ow rates307 and test a variety of process routes. it is essential to carry out detailed process simulation and thermal integration exercises to assess the viability of the full system under expected operating conditions. with three interconnected circulating uidised-bed reactors.296 Energy penalties can be further reduced in advanced CaL concepts that avoid the need of an air separation unit.315 Finally. Their most recent studies have been focused on evaluating the effect of steam and SO2 during calcium looping cycles. a rotary kiln calciner and a bubbling uidised-bed hydrator.305 Capture rates were limited in this rig to 4 mol CO2 m2 s1 because of the need to limit gas velocities to ensure sufficient holdup of solids in the 6 m riser. The CANMET Energy and Technology Centre designed and constructed a 75 kWth dual uidised-bed combustion system able to test CaL and oxy-combustion conditions. successful commissioning and positive initial results have been reported in a 1 MWth test facility (11. This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science sufficient bed inventory (400 kg m2) and solids circulation rate (0. The pilot test rig involves an entrained bed carbonator.284. the largest pilot globally for post-combustion CaL testing (1. The trend is consistent but slightly better than expected from lab scale testing.308 Ohio State University developed a 120 kWth plant to perform the Carbonation–Calcination Reaction (CCR) process. ITRI has plans to build (in the near term) a 1 MW pilot plant specially adapted for cement application (rotary kiln calciner). Downloaded on 05/11/2015 11:56:07.312 Fig. 10 General scheme of calcium looping cycle for CO2 capture in postcombustion or precombustion (between brackets) applications.304.5–2. 10.291 This section briey reviews the status of these two main groups of CO2 capture processes. Also.7 MWth) has been completed and successfully operated. a new 300 kWth facility for biomass combustion with in situ CO2 capture with CaO is being commissioned in Spain. 7. The reactors (5 m of total height) have an ID of 0.316 Energy Environ.2 kg m2 s1).306 A 200 kWth pilot plant was also recently completed at IFK. The synergy between CaL and cement industry has long been recognised. The CFB calciner has been operated in air-combustion and in oxy-red mode.309. Sci. University of Stuttgart that designed and operated a 10 kWth pilot plant. which consists of a CaL system with an intermediate hydration stage to prevent the decay in sorbent reactivity over multiple carbonation–calcination cycles.314. with efficiency penalties between 6 and 8% points with respect to reference plants without CO2 capture.300 Recent work has also included experimental studies.298 only recently there have been works investigating in detail these processes. The CCR process has been demonstrated to be highly effective and efficient in removing both carbon dioxide (over 90%) and sulphur dioxide (near 100%) under realistic conditions. Effective CO2 capture (80–90% capture efficiency) with a conservative value of calcium conversion to CaCO3 in the carbonator (10%) has been achieved. that can be effectively recovered in a steam cycle to generate more power.313 Capture efficiencies over 80% were obtained even with low activity and highly sulphated material. The plant includes two CFB reactors interconnected (15 m height) and is able to treat up to 2400 kg h1 of ue gas from an existing 50 MWe CFBC power plant. This limitation was removed at IFK. as shown on the right hand side of the plot.302. This reactor functioned as an effective absorber of CO2 as long as there was a Fig. desulphurisation. even with highly deactivated calcium oxide.310 In Taiwan.1 Post-combustion CO2 capture by CaL For large scale novel energy processes such as the CaL system. Although the basic idea is not new. A variety of research groups have recently conrmed the inherent thermodynamic advantages of the post-combustion Ca-looping concept using oxyfuel combustion. evaluate power generation efficiencies and conduct a transparent benchmarking exercise against more mature CO2 capture technology options. by transferring heat from a high-temperature source to the calciner. consisting of a CFB carbonator (12.View Article Online Review proposed a practical solution for the calcination problem: the oxy-combustion of an additional ow of fuel in a uidised-bed calciner to provide the “Heat” arrow of Fig. INCAR-CSIC designed and operated a 30 kWth test facility made up of two interconnected circulating uidised-bed reactors (0. But this may be considered not to be an energy penalty if the solid purge is used for cement applications. Experimental results showed capture rates close to those expected in large scale commercial systems (up to 10 mol m2 s1).1 m ID) that reported capture efficiencies between 70 and 97% under realistic ue gas conditions in the carbonator reactor. 2014. which may be operated with lower partial pressures of CO2 by introducing steam.311 In Spain. which is around 8–10% for natural limestones. but with higher plant simplicity and lower plant cost.334 In the AER process. etc. By coupling an endothermic and an exothermic reaction in the same solid matrix.331 the LEGS process332 or the “Calcium Looping Process” (CLP).View Article Online Energy & Environmental Science Published on 13 September 2013. that can be operated at intermediate temperatures (around 650 C) and can yield over 90% of H2 purity on a dry basis.328 investigated the potentiality of a SER process coupled to a combined cycle. 7. However. Simple CFB reactor models have been used to interpret results from a test facility at CSIC and IFK. especially for those that require highpressure operation to access higher efficiencies. a biomass gasier of 8 MWth interconnected with a circulating uidisedbed combustor has been successfully operated. reaction rate. Downloaded on 05/11/2015 11:56:07.) of the functional material in the system.336 a novel process has recently been proposed that employs the exothermic reduction of CuO with a fuel to supply the heat required for CO2 sorbent calcination. calculating a net efficiency of 50.312 for details). These will be essential tools for future scaling up of the technology. the benets of the sorption enhanced reforming process.340 and suitable materials are also being developed. Although particles or pellets can continuously be replaced by fresh (low cost) material. since the heat is directly transferred from the metal to the carbonate.325–327 Romano et al.321 have recently adapted their comprehensive model for CFB combustors to the carbonation reactor. competing sulphation/sulphidation reactions. tar. It has also been observed that the transition between the fast and slow regimes takes place quite suddenly at a given level of conversion and that this level of conversion decreases when the number of carbonation–calcination cycles is increased.330 Different congurations for the gasication of coal have been proposed in order to improve thermal and CO2 capture efficiencies. the calcination step of CaCO3 in a rich atmosphere of CO2 remains a serious challenge for CaL practical applications. it is obvious that the design and operation of any CaL system is highly sensitive to the quality (in terms of CO2 carrying capacity.339. methanol or ethanol. CaO and CaCO3 catalytically enhance the benecial destruction of tars. These processes offer signicant potential for efficiency and economic improvements. featuring the production of electrical power via a close integration of the SER process with a hightemperature Solid Oxide Fuel Cell (SOFC). Sorbent capacity tends to stabilise at very high cycle number at a residual conversion. 7. As mentioned above.329 evaluated the feasibility of a novel ZEG power concept. close to thermal neutrality. reactor and process level.342 7..338 Recent works have demonstrated the theoretical viability of the novel Ca/Cu looping process. the overall process is reduced to a single reaction step.341. obtaining a ue gas rich in CO2 and readily separable H2O. Meyer et al.289 In principle. below 5 g m3. This stream of new experimental data from increasing scales should provide a strong basis for improved models at the particle. CO2 capture with CaO during solid fuel gasication can be considered the rst application of CaL.335 yielding a product gas with a high H2 content of 35–40% (dry basis) and low content of condensable higher hydrocarbons. 130–189 Review the gasier. particles of CaO will experience repeated cycles of carbonation and calcination. In 150 | Energy Environ.2% with a carbon capture ratio of 88%. Sci.7 MWth pilot plant of la Pereda (see Arias et al.302. which are comparable with those values obtained for a competitive technology based on autothermal reforming. but they usually involve higher technical complexity. mechanical resistance. such as propane.2 Pre-combustion CO2 capture by CaL As noted above. obtaining efficiencies close to 77% with 100% CO2 capture and no NOx emissions. and the main experimental results investigating the concept at laboratory scale are reviewed by Harrison. it must be noted that this is not designed as a CO2 capture system since the CO2 captured by CaO is released in the air-combustor.333 The gasication of biomass in the presence of CaO has also been investigated as sustainable path for the production of hydrogen. high fuel conversions and minimal CO formation.318–320 Hypp¨ anen and co-workers319. Several studies have been recently reported on mathematical modelling of natural gas SER processes322–324 and the SER concept has been also proposed for alternative fuels.317 More elaborated carbonator models have been recently reported that take into account basic hydrodynamics in the riser and including the effect of SO2 co-capture and ash presence in the reactor. the presence of CaO drives the WGS equilibrium towards H2 formation and the heat released from the carbonation reaction provides heat for the endothermic gasication reactions. Furthermore. such as the HyPr-RING process. On the basis of the unmixed reforming concept.313 The observed loss in sorbent reactivity has been attributed to the drop in internal surface area and associated increase in pore size by sintering. a higher efficiency and lower equipment cost can be achieved.337. 11 Evolution of sorbent utilisation with the average number of carbonation–calcination cycles of particles in the 1. following a similar tendency for a wide range of particle sizes and reaction conditions. The carbonation reaction is characterised by a fast chemically-controlled rate followed by a slower reaction stage controlled by the diffusion through the CaCO3 layer.303. It is generally accepted that a fast decay in CO2 carrying capacity in the rst 20 cycles is almost unavoidable for natural sorbents. calcium looping can be combined with reforming and/or gasication processes to produce a hydrogen-rich gas. In general.3 CaO performance as a CO2 sorbent In CaL processes. Fig. SER. For natural gas. 2014. This journal is © The Royal Society of Chemistry 2014 . 351 studied the integration of the sorbent cost and its carrying capacity and mechanical performance for different options applied to an existing coal-red power plant.347 reported sulphation kinetics of CaO particles at low levels of conversion to CaSO4.345 have recently provided an elegant carbonation reaction rate model that seems to be able to explain most observations using a mechanism well established for other gas–solid reactions: they model the CaCO3 growth as islands on the CaO surface. the size and shape of the channels and cages as well as the Si/Al ratio. Despite the relative high heat of adsorption (36–37 kJ mol1). the heat of adsorption). which makes them very promising candidates for CO2 separation from ue gases. The large make-up ow of fresh limestone characteristic of most CaL systems allows for lower CaSO4 content in the system than in equivalent desulphurisation units using CaO. the cycle time (i.364. The thickness of the carbonate layer formed on the free internal surfaces of CaO is a critical parameter to explain the end of the fast reaction period. high selectivity for CO2. The selection of the best samples cannot be based only on their adsorption properties (i.350 Several approaches have been investigated to improve initial sorbent properties and/or reactivate spent sorbents.363 They are generally characterised by a relatively high CO2 capacity at low pressure. Downloaded on 05/11/2015 11:56:07. the sizes and heights of the CaCO3 product island increases while the island density decreases. high hydrothermal and chemical stability. pressure or vacuum swing adsorption (PSA or VSA) vs..284. However. Lisbona et al.356. capacity. the loss of performances due to the presence of impurities in the feed stream. R&D activity continues on the main techniques explored for sorbent improvement: hydration. good mechanical properties. Review attrition of the sorbent and the subsequent elutriation of nes. for precombustion applications higher activities may be desirable. as well as low costs of synthesis. and synthetic sorbents. MOFs (metal–organic frameworks).2. kinetics) because other factors may play a crucial role in the overall process. the regeneration energy demand (i. With the increase of reaction temperature.1 Zeolites Zeolites are crystalline aluminosilicates characterised by a highly ordered open structure.286. For this reason. a large variety of functionalised (mostly amine-based) adsorbents has been recently produced. Arias et al.343 which can be very signicant. The slight increase in the carbonate conversion in each cycle sustains the residual activity at around 0. Particles have been shown to break up mainly during the rst calcination. some important phenomena are not well explained by this simple theory.361 A different method for reactivation has also been proposed recently:362 a small regeneration reactor (recarbonator) is added between the carbonator and calciner vessels to recarbonate the particles leaving the carbonator (calcination– carbonation–recarbonation cycles) using a small ow of pure CO2 from the calciner’s off-gas. heat of adsorption. It is noteworthy that even when fully degraded in reactivity. a high value compared to many other potential sorbents.e. sorbent cost and operational cost. However. 7. which is close to the optimum design target for post-combustion systems. not only with regards to the costs of synthesis but also to the size of the equipment (i. and by ash fouling. Low temperature adsorbents A large number of adsorbents have been recently proposed and investigated as possible candidates for carbon capture at low temperature. The calcination reaction of highly cycled particles in a CaL is assumed to be very fast. They can differ greatly for the framework type.355 283.1 bar. fast adsorption/desorption kinetics.15 to 0. the hydrothermal stability. Only a few parameters are needed to t the observed carbonation rate curves in a wide range of temperatures. Based on these observations the best adsorbent should have high CO2 capacity at low pressure. With regard to carbon capture applications.287 Low cost methods based on co-precipitation can yield synthetic sorbents with high melting points and a carbonation conversion above 75% aer 50 cycles. 130–189 | 151 . Open pore structures of the sorbent in a CaL can also alter the rate and the extent of sulphation. at temperatures between 15 and 35 C. type X and A zeolites have been widely investigated.287. are the most widely investigated classes of adsorbents.286 doping. The fast carbonation stage is completed when these islands merge.16 g CO2 per gram. In addition.357 The use of supports like alumina358 or cements containing CaO and Al2O3359. attrition has been found to be highly sensitive to limestone choice.346 Sulphation rates of CaO in CaL reactors (carbonator or calciner) are also a recent subject of investigation.352–354 283. Attrition is another important issue in CaL because it affects capture efficiency. In general.344 Li et al. economic criteria have to always be taken into account.368 the high working capacity and selectivity make zeolite 13X one of the best choice Energy Environ. but this has only recently been conrmed experimentally.View Article Online Published on 13 September 2013. CaO from natural limestone still takes up 0.e. but many still require detailed studies at the process level to ensure their viability for large-scale commercial applications. whilst Anthony and co-workers348 focused their investigations on the performance of synthetic Ca-based sorbents. The very encouraging results obtained are opening a new eld for the investigation of new possible adsorbents for carbon capture applications. Sci.e. as promising candidates for CO2 separation. the volume of the adsorbent needed).e.349. In recent years a considerable research effort has been put in the development of a new class of adsorbent. 2014. thermal pre-activation. temperature swing adsorption (TSA)). equilibrium and kinetic properties and process selected.364–371 Generally 13X is indicated as the best candidate for post combustion PSA applications with values of the CO2 uptake between 2 and 3 mol kg1 at 0. 360 have recently been shown to improve the durability of CaO sorbent (some of them above 0. such as the temperature dependency of the CO2 carrying capacity and steam effects. Zeolites.50 g g1 sorbent aer 30 carbonation–calcination cycles under severe calcination This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science conditions). In addition. 8. as well as carbon-based materials. They demonstrated that the optimum CO2 carrying capacity that involves minimal heat requirements in the calciner is relatively modest (at around 20% of Ca conversion). 8. 388 One of their main attractive features is the possibility to modify their structures and functional properties by changing the building blocks used in their construction: this gives the incredible advantage of nely controlling pore dimension. zeolites are generally highly hydrophilic. Liu et al. an increase of the CO2 capacity is observed at higher temperatures while at lower temperatures.389. the position and the grade of occupancy of the extra-framework cations may be responsible for hindering diffusion of CO2 due to the blockage of the windows of the structure by the cations. the size.375–379 Deviations from the expected trend have also been reported for some types of zeolites due to the high basicity of the framework. the higher charge density of the smaller cations should increase the electrostatic interaction between the CO2 and the cations. despite their relatively low capacity at low partial pressures.397 The higher ionic character of the Mg–O bond improves the affinity with CO2. activated carbon showed a lower uptake and selectivity at lower pressures. The adsorption properties of activated carbon can be signicantly improved by the incorporation of amine functional groups into their porous structure.View Article Online Published on 13 September 2013. but on the other hand.. but. Co-. the presence of water induces an alteration of the electric eld reducing the strength of interaction between the quadrupole of CO2 and the cations. The CO2 chemically reacts with the amine groups forming bicarbonate and/or carbamate. their high thermal stability and the fully reversible CO2 adsorption make them very promising materials for pressure-swing processes. Despite the good adsorption properties for CO2. Ideally. The possibility of application of carbon molecular sieves in a PSA process for CO2 from ue gas was recently investigated by Carruthers et al.374 and Lee et al. resulting in a lower uptake.373 and. for which the presence of extra-framework cations has been proved to induce considerable distortions in the structure. and chemical potential of the surface.398 reported that the H2O molecules interact specically with the strong adsorption sites of Ni-MOF-74. 130–189 Review CO2 uptake follows the sequence.392–394 Mg-MOF-74 is characterised by a high selectivity for CO2395 and the heat of adsorption is generally higher than the one of zeolites with values of about 47 and 41 kJ mol1 for the Mg and Ni form respectively.405 As part of the carbon based materials new developments are in progress with regard to the carbon nanotubes (CNT) for This journal is © The Royal Society of Chemistry 2014 .376 In this regard.404 investigated the use of activated carbon in a VPSA process to capture CO2 from ue gas.368.. Their presence not only induces modications of the electrical eld inside the pores. it makes the Mg form more hydrophilic than the analogous Ni form.372. physisorption is predominant and the loss of porosity due to the amine functionalisation has a crucial role in the nal CO2 uptake.389 MOFs generally show higher CO2 capacity at high pressures compared to zeolites.390. but it can also change the morphological structure of the zeolites. SOx and NOx) showed a signicant deactivation of the samples with the Ni-MOF-74 demonstrating a greater resistant to degradation. the effect was less pronounced for Ni-MOF-74. As a result. In addition.365.380.1 bar using the ZLC method.403.406 Moreover. 8.. Siriwardane et al.369 For this reason 13X is generally used as a benchmark material for lowtemperature adsorbents for carbon capture applications. shape of the channels.3 Carbon-based adsorbents Carbon-based adsorbents are synthesised by the thermal decomposition of carbonaceous materials and have been investigated and used for a wide range of gas separations. Values of the heat of adsorption are generally lower for the activated carbons than for other adsorbents with values in the range from 15 to 30 kJ mol1.399–402 Shen et al.and Mg-MOF-74) was carried out by Hu394 at the conditions of interest for postcombustion carbon capture at 38 C and 0. Energy & Environmental Science for CO2 capture from ue gas streams. which has a predominant role relative to the strength of the quadrupole interaction.393.382–387 A recent study of Lozinska et al. Sci. with values of the CO2 capacity for Mg-MOF-74 being almost double than that for 13X. Downloaded on 05/11/2015 11:56:07.389.373 Detailed studies on the effect of the presence of small amounts of water on the CO2 uptake of zeolites were presented by Brandani and Ruthven372. resulting in a higher uptake. causing a nonrecoverable loss of CO2 capacity. more recently by Li et al. Tests in the presence of impurities (water. From the study. MOF-74 and its politypes have shown attractive features for carbon capture. similarly to what reported by Palomino et al.406 which is promoted at higher temperatures. The nature and the distribution of the cations inside the zeolite framework play a crucial role in the nal CO2 adsorption properties. This trend of the CO2 uptake with the increasing charge density has been observed by several authors.364. it emerged that. which ultimately gives the possibility to build adsorbents with the desired adsorption properties.391 although the CO2 capacity was found to reduce in presence of water for all the materials. a gating effect was detected for the Na-Rho type due to the presence of CO2.399 compared the adsorption properties of commercial activated carbon with 13X and 4A.402 The study concluded that despite the lower capacity relative to other adsorbents the low heats of adsorption and the stability of carbon-based adsorbents make them competitive for CO2 capture from ue gas. obtaining relatively high values for the recovery and purity of CO2.381 On the other hand.405.379 reported that the combination of the framework distortion and the hindering effect of the cations resulted in an extremely slow diffusion of CO2 (measured using the ZLC technique). Studies to compare the effect of water on CO2 adsorption for Ni-MOF-74 and commercial zeolites were performed by LeVan et al. Mg > Ni Co > Zn. relative to the zeolites. an interesting case is represented by the Rho zeolites.378 8. inuencing the adsorption kinetics.. Ni.396. relatively slow kinetics are generally observed. An extensive study on different MOF-74 samples (Zn-.375 concluding that the presence of even very small amount of water greatly reduces the adsorption performance of zeolites. but they maintained higher hydrothermal stability. The trend of the 152 | Energy Environ. 2014.391 With regard to the low pressure applications. 7.2 MOFs The structure of MOFs consists of organic–inorganic hybrid networks formed by metal ligand bonds. 1 bar and 25 C was comparable with the one of a typical zeolite.412–414 induced a series of modications on MCM-41: they synthesised a pore-expanded form (PE-MCM-41) and successively introduced amine groups in the expanded form (TRI-PE-MCM-41). ETI422 just announced the award of £20 million funding for a 5 MW project that can be used for a new-build CCGT or retrotted onto one. The material exceeded the DOE targets of >90% CO2 capture with >90% CO2 purity during tests with 200 standard l min1 of ue gas.4 Mesoporous silicas Mesoporous silicas are generally characterised by low CO2 uptake due to the weak surface interaction with CO2 molecules.. 2014. in some cases.415. The test results were presented in Pittsburgh. 13X (2. but the nal aim is to have a commercial technology by 2020. the availability of data on these projects in the future will represent a crucial step towards the deployment of adsorption processes at commercial scale. The initial stage of the project is lab scale studies. the TRI-PE-MCM-41 sample. Energy Environ. USA. 130–189 | 153 . but the increased complexity of the adsorption process may. Multi-walled CNT functionalised with APTES have shown a signicant improvement of the CO2 uptake compared to the pristine sample. which is a very important advantage for the possible application of the sample for CO2 capture applications. 8. which combined the advantages of a large pore structure due to the presence of amine groups. Xu et al. the US DOE419. Downloaded on 05/11/2015 11:56:07. 7. The pilot plant will be located in the Southern Company – Alabama power Co. showed a dramatic improvement of the adsorption capacity. A pilot plant that was designed based on the results from a detailed simulation study. however. 8. The ATMI/SRI BrightBlack423 microporous carbon was recently tested at a coal-red steam production facility operated by the University of Toledo in Ohio. Inventys claims that their VeloxoTherm™421 process can capture CO2 for 15 US$ t1. this article will now focus on more long-term options. Victoria. very promising results have been obtained recently. a signicant increase of CO2 uptake at low pressure has been shown compared to the pure silica. One of the rst pilot plant projects was the CO2CRC H3 project417 lignite-red power plant based at International Power’s Hazelwood Power Plant. the water and subsequently SOx/NOx from the ue gas. the amine-modied sample exhibited a signicant increase of the CO2 uptake in presence of water. has been constructed. lead to an overestimation of the adsorption capacity. A This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science purity of about 71% and a recovery of about 60% were achieved aer continuous running of the process using a simple 6-step cycle (without purge) for a week. Additionally. Sci.411 Belmabkhout et al. reporting an increase of the CO2 capacity with the PEI loading and temperature (with a maximum at 75 C for the sample with 75 wt% of PEI). Pennsylvania. The advantage of having large and uniform pores is that it is possible to introduce surface modication. Australia. Not much information is available at the moment on the pilots due to the early stages of development of most of them.407–409 Published on 13 September 2013.5 Pilot-plants development and testing At present. there was not a signicant improvement in the low concentration region. while the adsorption process was found to be strongly kinetically controlled. Based on a lab scale 1 kW plant with supported amine sorbents in a circulating uidised bed developed by ADA Environmental Solutions. On the other hand. The research project was completed in 2011 and the performance of commercial and novel adsorbents was investigated at high humidity levels in the presence of SOx and NOx with a 3-bed multi-layered vacuum swing adsorption process. USA at the 2012 NETL CO2 Capture Technology Meeting. MAST Carbon International and Doosan Power Systems as partners. plant and should be completed by the end of 2013.416 studied the adsorption performances of PEI-impregnated MCM-41 under different conditions. the column operated for approximately 7000 adsorption–regeneration cycles with no loss in process or adsorbent performance and no signs of adsorbent degradation. Nanyang Technological University (NTU) and Institute of Chemical and Engineering Sciences (ICES). The technology involves an intensied temperature swing adsorption process with structured adsorbent and steam regeneration in a rotating adsorbent wheel.2 mol kg1). A layer of CO2-selective materials was then added. Special attention is focused on the power consumption by the vacuum pumps so that a reliable estimate of the energy penalty may be obtained. Even though the capacity is comparable with 13X. What makes them attractive for carbon capture is the possibility to introduce functional groups (usually amine-based groups) to increase the affinity with CO2. CO2 utilisation and mineralisation. This will include carbon capture from the ambient atmosphere. As a result of the introduction of functional groups. The PE-MCM-41 exhibited a higher CO2 uptake at high pressure than the non-modied MCM-41. and was commissioned in 2009 Latrobe Valley. a few pilot scale demonstrations are investigating the effectiveness of low temperature adsorbents for CO2 capture. especially in the low pressure region. The consortium will be led by Inventys with Howden.410 The adsorption properties are mostly inuenced by the density of amine active sites and by the accessibility to the sites (pore size). rst. The project partners are now looking at scaling up to pilot scale testing.420 has funded a 1 MW pilot plant. The value of the CO2 uptake at 0. reducing possible steric hindrance of the adsorption sites. which includes a collaborative project418 between the adsorption and process systems research groups at National University of Singapore (NUS).View Article Online Review low-pressure carbon capture. Having reviewed a number of technologies for carbon capture from industrial and power station sources. The Science and Engineering Research Council (SERC) of Singapore in 2009 launched a research programme on Carbon Capture and Utilisation (CCU). 1 m long columns with 0. as well as Rolls Royce for specialist engineering support.3 m internal diameter were used and the plant is expected to capture around 3 tCO2 madsorbent3 per day using a simple 4-step Vacuum Swing Adsorption (VSA) with Zeochem 13X and synthetic dry ue gas. Multi-layered adsorbents were used to remove. the thermodynamic minimum energy required to extract CO2 from ambient air is 20 kJ mol1 compared with 8. the dispersion of naturally occurring bases such as serpentine and olivine across the land. there are also signicant disadvantages to the technology. Other negative emissions technologies include bioenergy enhanced carbon capture and storage (BECCS). and the enhancement of biological CO2 sinks such as reforestation. augmented ocean disposal (or ocean liming). Removing and concentrating CO2 from air at 390 ppm to a pure stream (>90%) implies a greater energy input. In addition.. as is the case for CCS systems. provided there is access to an available energy source and sequestration sites. Baciocchi et al. we will only very briey review recent developments in air capture technologies here. for more information. afforestation and aquatic biomass via ocean fertilisation. where direct capture and integration into a centralised CCS network would be either impractical and/or uneconomical. such as deserts. heating. The CaO powder is then dissolved in water to regenerate the slaked lime solution.434 Aer the contactor. Firstly.View Article Online Energy & Environmental Science 9. activated carbon and alumina-based molecular sieves (adversely affected by moisture and low adsorption capacities at ambient conditions). typically quoted as 240–500 US$ tC1 (65–136 US$ tCO21).6 and 11.432 convection tower433 or spray-tower contactor system. Sci. the NaOH solution is regenerated via caustic recovery (or causticisation). This has signicant implications on energy consumption and the required plant size. direct air capture offers a number of purported advantages. Compared with traditional CO2 capture from concentrated point sources. biochar production and utilisation. Whilst both capture processes require energy to regenerate the sorbent. Air capture could also offer an option for addressing CO2 emissions from mobile and distributed sources. the reader is encouraged to read a recent review by Goeppert et al. which is far greater than the thermodynamic minimum energy requirement. Two main approaches have been proposed for direct air capture (i) wet air capture systems and (ii) dry air capture systems.3 kJ mol1 to capture and concentrate CO2 from the ue gases of natural gas-. cooling or pressurising will not be economical. from $50– $120 tCO21 depending upon source and capture technology).428 However. Downloaded on 05/11/2015 11:56:07.431 9.1 Introduction Direct air capture is the process of removing CO2 from the air and generating a concentrated stream of CO2 for sequestration or re-use. such as vehicles. As a consequence. capture technologies that require pre-processing of air. dried and transferred to a rotary kiln where it is calcined at temperatures in excess of 900 C to produce a concentrated stream of CO2 and a calcium oxide (CaO) powder.425 Direct air capture has been practiced on a small scale for decades for the purpose of maintaining safe levels of CO2 in 154 | Energy Environ. where slaked lime (an aqueous solution of Ca(OH)2) is reacted with the dissolved sodium carbonate (Na2CO3) product to form a calcium carbonate (CaCO3) precipitate mud. the actual energy consumed by air capture technology will be signicantly larger than the thermodynamic minimum. such as drying. For example. Furthermore.6 GJ tCO21 (334–510 kJ mol CO21) with drying. The CaCO3 mud is ltered. or carbon dioxide removal (CDR) technologies. it has been suggested that direct air capture technology could potentially be situated anywhere. pre-heating and calcining of the CaCO3 accounting for the majority of the total energy demand. estimates were CO2 compression and air separation to produce O2 for an oxyfuel kiln. As a consequence. Direct air capture technology Published on 13 September 2013. wasteland and the ocean. and zeolite. and coalred power stations containing 5% and 15% CO2 respectively at 65 C. CO2 abatement costs for this process are high. 7. air capture provides a means of adjusting the atmospheric CO2 concentration in the increasingly more likely event that mitigation efforts fall short of targets and the atmospheric greenhouse gas inventory reaches dangerous levels or takes a trajectory towards stabilisation at dangerous levels.430 cryogenic separation (cooling and compression required). the volume of air that must be handled to capture comparable amounts of CO2 to traditional CCS technologies is far greater. The requirement of substantial thermal energy for lime regeneration represents a signicant drawback of this process. direct air capture technology could be installed by storage site operators to manage fugitive emissions from the CCS network and leakage from geological formations.436 much higher than some estimated cost of CCS at 30–50 US$ tCO21 437 (some authors of this paper might suggest a more conservative range of costs. For those seeking more information than this brief overview. Zeman et al.4 kJ mol1 and 5. CO2 must also be removed from air prior to air liquefaction to avoid operational issues associated with dry ice formation. fuel use in buildings and geographically isolated industry. However. These technologies are beyond the scope of this paper. 2014. It belongs to a group of technologies referred to as negative emissions.431 This uses aqueous sodium hydroxide (NaOH)based solutions to extract CO2 from ambient air in a packedcolumn.435 Other energy intensive processes considered in the Baciocchi et al. though the interested reader may refer to a recent techno-economic analysis of negative emissions technologies by McGlashan et al. estimated that process energy demands are likely to range between 7. Furthermore. estimated that the energy demand of a large-scale MEAbased process for CO2 capture from concentrated sources would be 181 kJ mol1.429 This rules out technologies typically used for small-scale air capture such as membrane separation (large pressure gradients and multiple passes required to achieve a high-purity CO2 stream).2 Wet air capture systems-the soda/lime process The most developed approach for wet air capture is the soda/ lime process.424 In fact. 9. the energy demand scales proportionally to the mass of CO2 captured as opposed to the volume of air processed. and treatment of a vastly greater volume of gas than CO2 capture from concentrated point sources. 130–189 Review submarines426 and spaceships427 though it is important to note that the concentration of CO2 is in these locations is signicantly higher than that within the atmosphere. Recent papers by the American Physical Society438 and House This journal is © The Royal Society of Chemistry 2014 . further work is required to address and manage issues associated with high energy requirements. Carbon cost. 2014. or polymer support. Fuel cost.4 Dry air capture systems Dry air capture systems typically employ solid organoaminebased adsorbents where amine functional groups are either physically or chemically bound to the surface of a porous-silica. metal oxide. 90 kJ mol1 compared to 179 kJ mol1. particularly in the case of the soda/ lime process. Lackner et al. One important target is that of having 15% of the UK’s energy supplied by renewable resources by 2020. large evaporative losses during liquid–air contacting and the high corrosivity of the strong-base absorbents solutions. Annualised capital cost (a function of the initial installed cost. Downloaded on 05/11/2015 11:56:07. on the basis of highly contentious assumptions concerning mass production and autonomous operation. The temporal.5 Conclusions and future scope Laboratory scale research has demonstrated that direct air capture is technically feasible. and avoid the foreseen energy gap if this investment is not made.429. given that one will typically select a payback time and discount rate such that 80% of the original investment is paid back within 10 years.443 The positive charge associated with the quaternary amines is balanced by mobile hydroxyl or carbonate counter-ions.1 Introduction The aim of this section is to review the recent literature pertaining to the retrotting of post-combustion CO2 capture technology to fossil fuel-red power stations and then discuss the impact of this retrot on the merit order of such a decarbonised power station. have developed an alternative material for extracting CO2 from ambient air. increased deployment of renewable energy technologies.447. in the region of US$600 and US$1000 per ton of CO2 respectively.439 have stated costs may be even higher. Cost estimates vary substantially ranging from as low as 20 US$ tCO21 to as high as 1000 US$ tCO21 and it is highly likely that air capture will offer one of the most expensive options for mitigating climate change. i. however. A simple analysis by Brandani indicates that the cost of air capture relative to CO2 capture from a power station should be around a factor of ten higher. It is considered by a number of the authors of this article that these costs are unrealistic. the future carbon price must also be high.442 Much of the work to date has focused on developing sorbents with high CO2 capacities and has neglected to use realistic desorption conditions. 10. the future of large-scale direct air capture as a climate change mitigation technology remains uncertain. the UK is undergoing an EMR exercise which is intended to create a policy environment conducive to sufficiently de-risk the capital investment associated with the installation of new power generation capacity to support investment by the international capital markets in UK power generation. Sci. economic and policy context of this discussion is in that of the UK in the 2030s where the current electricity market reform445 (EMR) discussion has been completed and there are signicant amounts of intermittent renewable power446 in the UK energy system. other. Air capture R&D is still in its infancy. At present. cheaper options for addressing climate change such as reducing the carbon intensity of electricity generation through efficiency savings in existing power plants. However.3 Alternative wet air capture systems Published on 13 September 2013. 9. commercial deployment of air capture technology will depend on whether the technology can be proven on a large scale and at a cost that makes it protable to do so. has led to very high estimated mitigation costs. However. Air capture costs for a system employing this adsorbent have been estimated by the purveyors as 15 US$ tCO21 with initial costs including infrastructure and maintenance costs of 200 US$ tCO21.g. though it should be noted that these costings are disputed by researchers within the air capture community. nuclear power and CCS should be aggressively pursued before air capture is considered. and release CO2 when wet. Ultimately. the high energy requirements for sorbent regeneration.441 The energy required to regenerate titananates is much lower than for CaO. carbon.448 carbon prices are likely to be mandated by the EMR (at least in the UK.e. risk is associated with the probability and magnitude of an unfavourable outcome (e. For this to be realised. although there may be some market element to this as well) and electricity prices are Energy Environ. payback time and discount rate). far behind the more This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science conventional climate change mitigation technologies. heat integration. more than the cost of extracting and storing atmospheric CO2. 130–189 | 155 . which adsorb CO2 when dry. in the context of a power station. comprising of an anionic ion-exchange resin with quaternary amine functionality dispersed onto a polypropylene membrane. Load factor and dispatch frequency (how much and how oen a power plant can sell energy to the grid). Some progress has been made towards reducing the energy demand associated with sorbent regeneration through the use of alternative causticising agents and other improvements. the paper and pulping industry have been developing and piloting an alternative approach that involves direct causticisation with titanates. prot below expectations). Taking prot as simply the difference between annualised revenue and cost.446 At the time of writing (early 2013).444 9. Desorption can be achieved via either contacting the material with a humidied gas stream or directly with water.440 9. For this reason.View Article Online Review et al. opting instead for desorption at elevated temperatures in an inert gas stream generating a dilute CO2 stream. From the perspective of a potential investor. and it is a function of: Electricity price (feeding into a revenue stream). 7.. In attempts to eliminate the energy intensive lime regeneration step. Wet air capture is the most developed approach. Retrofitting CCS to power stations – the case for flexible operation 10. at the simplest level of integration.00 35.View Article Online Published on 13 September 2013. This requires the application of appreciable quantities of energy. (kJ kg1) 130. Downloaded on 05/11/2015 11:56:07.e.2. (bar) Temperature. However. 10. Consequently.02 MPa). evident that the least risky option will be to invest in a power station that is fuel exible. but representative numbers are presented in Table 5. in turn. In this section.2. meaning that the rate at which they can ramp up (or down) their power output is relatively low. one simply needs to connect the exhaust gas stream from the FGD process with the inlet to the absorption process.00 2. The steam conditions at the inlet to and outlet from each of the HP.08 535.3 Sub-critical power-station. dispatch frequency. in order to add a small amount of pressure (>0. 130–189 Review 10. load following) manner. QRegen. Amine-based CO2 capture processes comprise two distinct unit operations—absorption and desorption (or solvent regeneration). therefore. One can envision a scenario in which the degree of steam extraction for the solvent regeneration can be manipulated to instantly provide more steam for power generation when circumstances dictate. We exclusively consider this technology option as it has the inherent advantage that it is an “end-of-pipe” technology. the CO2 rich solvent needs to be heated in order to recover the CO2 and reuse the solvent. the main sources of risk associated with investing in a power plant. IP and LP turbines.50 2. we provide high-level descriptions of the various unit operations and sub-processes which come together to compose a decarbonised power plant. or RLHX. IP and LP turbines are typically specic to a given plant. Energy & Environmental Science essentially pegged to fuel prices (gas in the UK). super-critical power plants are less exible in their operation than their sub-critical counter parts. This energy may be. this energy penalty is offset via heat exchange between the hot. and that required to break the chemical bonds between the CO2 and the amine solvent. In part. The authors would emphasise that this rationale (fuel and operational exibility) should hold for investment into any fungible energy network.00 38. It is interesting to note that. lean solvent exiting the reboiler and the cold. by post-combustion CO2 capture. has low greenhouse gas (GHG) emission per unit of output and can operate in a exible (i. see the section above on solvent absorbtion. 12). an average exit temperature for the rich solvent stream would be approximately 87 C.3 Integration strategy In integrating the power and capture plants. In addition to the HP. we rst provide a high level description of post-combustion CO2 capture processes. similar to those already in place for the mitigation of SO2 emissions. this option was found to have a relatively low efficiency and was subsequently abandoned as a Table 5 Representative steam cycle conditions for a sub-critical power plant.2 Description of sub-systems In this section. Sci.. 10. P. However. The remainder of this section is laid out as follows.0 — — 41.50 0.449 This paper did not supply temperature data for the IP out/LP in streams HP in HP out IP in IP out LP in LP out Pressure. we highlight the main relevant characteristics of coal-red power stations for exible operation. As discussed previously. ( C) Enthalpy. This is important when calculating the opportunity cost associated with steam extraction for solvent regeneration. thermal driving force and the efficiency with which the RLHX operates. It is important to note that there are typically multiple steam extraction points in a given turbine (Fig.4 Future coal-red power stations. Adapted from Asthana and Panigrahi. the steam cycle has one steam reheater in addition regenerative heating of condensate through a train of feed water heaters.and super-critical coal-red power stations and of a gas-red power station. It is. 10. for further details. we refer exclusively to amine-based chemical absorption processes. QSens. 7.0 351. This will require passing the exhaust gas through a fan.2. In this context.g. ue gas desulphurisation (FGD) processes. This occurs in the socalled “rich-lean heat exchanger”.2 535.19 156 | Energy Environ.e. Some of the early integration studies proposed the addition of a separate natural gas ancillary boiler to provide steam for solvent regeneration on a post-combustion capture retrot on a coal power plant. rich solvent exiting the absorber. are the load factor.1 Post-combustion CO2 capture process. We then go on to describe the optimal means for the integration of the capture and power plants and discuss some operational strategies that are held to minimise the operational risk associated with these systems. the addition of a post-combustion CO2 capture process could actually be an advantage. IP and LP are not equal (DHIP > DHLP > DHHP).449. intermediate pressure (IP) and low pressure (LP) and they operate on a Rankine cycle. 10. QChem. e.451 This stream will still require 3. In this section. These gas–liquid separating processes are very well known and have been described in detail in a number of previous contributions. high pressure (HP).2. i.2 GJ tCO21 recovered as energy input. The reason for this is the lack of steam drum in the power plant. Conventional sub-critical coal-red power plants typically have three stages. to ensure that the exhaust gas has sufficient mechanical energy to overcome the pressure drop associated with the absorption column. sub. 10. fuel and carbon costs. despite their improved efficiency. the arguments presented herein are held to be equally applicable to any energy system comprising diverse generation sources. only a high-level overview is provided here. H. This concept is explored further below. T.450 It is evident that the specic enthalpy in the steam in the HP.5 3430 3100 3530 2861 2861 2366 This journal is © The Royal Society of Chemistry 2014 .2 Coal-red power station. The temperature of the rich solvent stream exiting the RLHX is clearly a function of the available heat transfer area.452 as is common practice for natural gas treating plants. partitioned into contributions required to heat the solvent. 2014. with or without CCS.8–4. their protability in a diverse energy generation system. From Asthana and Panigrahi. 7. transporting CO2 via pipeline will be the most cost effective mode of transport. QSub-cool. fuel and carbon (i. this capacity for exible operation will command a special premium.455 This concept has recently been quantitatively proven456 to provide an important reduction in operating cost456 and as a buffer between the dynamic behaviour of the power plant and the required steady state operation of a CO2 transport network. allowing CO2 to accumulate in an on-site solvent inventory can enhance this effect. have shown that adjusting the degree of solvent regeneration in sympathy with prevailing market prices for energy.18 generate power in a exible way. Fig. leading to an appreciable reduction in capital cost. 2014.4 Flexible operation of decarbonised power plants – towards risk mitigation 11. it has been shown that the optimal location for the extraction of this steam from the steam cycle is between the IP and LP turbines. and that obtained by sensible heat transfer by subcooling the condensate. the recovery of heat from the inter-coolers of the compression train was found to be especially important. The choice of transport will depend on the quantity of CO2 that needs to be transported. In particular. either by designing new solvents or by carrying out heat integration and recovery studies. Arce et al. The concept of storing CO2-rich solvent on-site was originally proposed by Chalmers and Gibbins.View Article Online Review Published on 13 September 2013. be returned with the minimum degree of subcooling in order to avoid an additional penalty on the power plant associated with returning large quantities of sub-cooled liquid to steam cycle. P ¼ 0. one can partition the contributions to QRegen into that obtained by the condensation of steam. increased solvent regeneration or a lower lean solvent loading at times of low energy prices.453 As before.25 MPa. 130–189 | 157 . and. ship.457 In most cases. 10. Downloaded on 05/11/2015 11:56:07. Thus. in any power generation network. a dense-phase uid). Sci. With the increasing intermittency associated with the diverse energy network envisioned for the UK in the 2030’s and beyond. As alluded to above. It has been shown19 that the fraction of QRegen obtained from QSub-cool is negligible.453 More sophisticated approaches to heat integration between power and capture plants and the CO2 compression train have also been investigated. Transport via rail or road is only expected to be feasible for moving CO2 on a small scale for specialist applications. the condensate should. a recent paper illustrates how the humidity of the inlet exhaust gas stream at the base of the absorber will play an important role in the process operation. the distance and terrain to be travelled. this energy is best obtained via condensation of saturated steam at P z 0.449 viable option in decarbonising power plants.454 shows how this can appreciably reduce the total energy penalty associated with the decarbonisation of the power plant. In particular. CO2 is compressed to a supercritical uid (sc-CO2) or liquid state (i. In the case of a sub-critical coal-red power station.e. The instances where transport by ship may prove more economical would be if CO2 needs to be moved over very large distances (>1000 km) or over large bodies of water. this idea can be used in conjunction with supercritical power plants to enhance their exibility. and reduced levels of solvent regeneration at times of high energy prices) can lead to an appreciable reduction in operating cost.2 MPa). 12 Energy & Environmental Science Schematic of sub-critical power station. It would appear that a dry exhaust gas will require a shorter column than a wet gas. Specically. Subsequently. therefore. as opposed to the power cycle condenser. for example. the condensate should be returned to the condensate heating train.e. we suggest that the position of fossil fuel-based power plants in the power generation merit order is changing. QCond. However. and the specications of the CO2 stream produced at the capture facility..2 As discussed in the introduction. rail or road. The vast majority of integration studies concentrate on the modication of the solvent phase. a recent contribution by Duan et al. Furthermore. Furthermore. CO2 transport 11. Once this steam has been condensed. therefore. CO2 exists This journal is © The Royal Society of Chemistry 2014 Basic operation Energy Environ. 11. direct extraction of steam from the steam cycle of the main power plant has become the preferred option. Owing to the desired conditions within the reboiler (T ¼ 120 C. the resulting condensate is then returned to the steam cycle. there are clear benets associated with being able to Prior to pipeline transport.1 Introduction CO2 can be transported by pipeline. The presence of impurities. there is an economic incentive to remove certain impurities down to very low levels and design CO2 specications for optimum oil recovery efficiency. There is also limited operational experience of onshore and offshore pipelines transporting CO2. However. methanol and glycols may also be present as a consequence of CO2 capture. The Dynamis project463 updated specications that were initially proposed for precombustion CO2 capture technologies as part of the ENCAP project464 to take into account safety and toxicity limits.461 11. transporting CO2 for storage purposes does not share this relationship and removing impurities in anthropogenic CO2 down to very low levels imposes a signicant energy and cost penalty on the process. and the equipment and infrastructure for loading and unloading CO2 at the loading docks. pipeline entry specications are set in order to minimise or even avoid these problems. Ships therefore offer the potential to collect CO2 from multiple sites on the way to the storage site and can better adapt to uctuations in the CO2 production rate of the emitter.4. intermediate pumping (or booster) stations are required at certain intervals along the pipeline. minimal gas treatment is required. and health and safety considerations. allowable levels of H2S. In the case of EOR. Operating pressures of existing CO2 pipelines are in the range of 85 to 210 bar where CO2 is a dense-phase uid over a wide range of temperatures. CO. Maersk are currently working on pressurised.372–98. O2. and In Salah. 130–189 Review rst purpose-built CO2 tanker. Table 6 provides a summary of the major long-distance CO2 pipelines currently operating. As a consequence.136% N2. containing other impurities such as CO. viscosity and compressibility.460 Work is on-going to develop ships with the capacities required for large-scale CCS deployment. capture process and gas treatment steps.1 CO2 specications. For shorter distances. Amines. H2S. has calculated optimum conditions for CO2 transport by ship of 6. 0. Downloaded on 05/11/2015 11:56:07. it is most efficient to transport CO2 as a cryogenic liquid. Ships are more exible than pipelines as they are able to transport CO2 in volumes far below the design capacity. However. which can ship up to 1825 tonnes of CO2 at 40 C and 18 barg. ow rate and composition. This is the most efficient phase for transporting CO2 by pipeline as it has both the high density of a liquid and the favourable ow characteristics of a gas. factors affecting the hydrodynamic properties of CO2. Therefore. Yara International charters the other three ships which have capacities between 900 and 1200 tCO21. SOx and NOx gases have been lowered in accordance with their short term exposure limits (STELs). To meet these specications. CO2 from natural sources is saturated with water and typically composed of 98.3 Existing experience Globally. important to ensure pressures drops are managed and pipeline pressures are kept above vapour–liquid equilibrium conditions to maintain a single-dense-phase ow and avoid liquid slugs and other operational problems that may eventuate if conditions fall within the region where a two-phase (gas–liquid) ow may occur. Sci. NOx and H2. though there are a few projects utilising CO2 from anthropogenic sources. 7.1 C and 74 bar.514% CH4 and trace amounts of H2S. SOx. Sleipner.191. booster stations may be avoided by increasing the pipeline inlet pressure.2 C. tends to be much less pure.4 Pipeline design and operation considerations CO2 pipelines must be designed and constructed at an optimal cost in such a way that they are reliable and safe to operate.. Ship-based transport systems require intermediate storage facilities. 11.462 Therefore apart from dehydration. pressure. To maintain sufficiently high pressures over long distances.462 Pipeline design is primarily inuenced by the required throughput and hydrodynamic properties of the CO2. such as density.5 bar and 51. therefore.107–1. Aspelund et al. CO2 specications for storage purposes will most likely be determined on the basis of cost-benet analyses. The exact levels will vary depending on the source.View Article Online Published on 13 September 2013. transporting food-grade CO2 in northern Europe.521–0. and storage sites to link continuous production of CO2 at capture facilities with discrete transport of CO2 by ship. Anthropogenic CO2 on the other hand. additional gas treatment measures such as regenerative absorption columns This journal is © The Royal Society of Chemistry 2014 . EOR specications tend to be strict (Table 7) as certain impurities will have detrimental effects on the process. The level of impurities that can be tolerated will depend on the storage method (or end use) and the transportation method. Therefore. 2014.457 Losses can be minimised by utilising a refrigerated container ship or by re-capturing and liquefying the boil-off gas. Ship-based CO2 transport experience is far more limited. more energy would be consumed for compression and thicker walled pipeline would be required. particularly water. may also lead to operational problems concerning corrosion. derived from natural gas production. As a consequence.350% CO2. including temperature. A few studies have attempted to dene CO2 specications for transport and storage purposes. 11. there are only four small ships. 1. 31. there is approximately 6000 km of pipeline infrastructure in operation for CO2 transportation purposes. Energy & Environmental Science as a supercritical uid above its critical point. In terms of CO2 transport by ship. NH3. Some loss of CO2 is expected as a consequence of boil off and the ship’s emissions would be in the region of 3 to 4% per 1000 km. semi-refrigerated CO2 tankers with capacities up to 45 000 tonnes. It is. for sequestration in saline aquifers at the Snøhvit LNG facility. gas hydrate and ice formation. most of which is based in the US and Canada for transporting CO2 to sites for enhanced oil recovery (EOR). however.459 At present.457 Anthony Veder Group operates the 158 | Energy Environ. it is not possible to maintain pipeline temperatures above the critical temperature in all situations. need to be modelled and characterised as part of the design process. regulatory and legislative requirements. posing minimal risk to local populations and the environment. At present.458 Large scale liquefaction would primarily involve cooling via compression and expansion of the feed gas. phase behaviour. dehydration and corrosion control. most of the CO2 used for EOR is sourced from natural deposits. 4 ml m3 65 C MMP MMP MMP Corrosion Corrosion Safety Operations Material integrity may be required in addition to the standard SOx and NOx removal (FGD. Impurities with lower critical temperatures and pressures than CO2. which is highly corrosive to carbon steel (the material typically used for natural gas and existing CO2 pipelines). reduce pressure and temperature drops along a set length of pipeline. 130–189 | 159 . although they did not dene tolerance limits for SOx and NOx based on their assumption that these impurities will not cause operational problems in the absence of a separate water phase. 4% and 10%).View Article Online Review Published on 13 September 2013. N2. which must be increased with increasing impurity content to avoid two-phase ows. This journal is © The Royal Society of Chemistry 2014 The presence of impurities also reduces the density of densephase CO2.465 This impacts the minimum operating pressure of a CO2 pipeline. Energy Environ.465 The Ecofys specications are similar to those dened by the Dynamis project.4 352 140 Gasication Plant EOR 1972 1. low NOx burners and SCR). Sci. A thicker walled pipeline or tougher pipeline material may also be required at a higher infrastructure cost. An aqueous phase may form if the water vapour content exceeds the saturation vapour level at any point within the pipeline. Table 6 Energy & Environmental Science Major long-distance CO2 pipelines465.465. Yan et al. Alternatively. 11. the pipeline would have to be operated at a higher inlet pressure. such as H2. CO and Ar. pipelines transporting CO2 containing large amounts of impurities must be operated at higher inlet pressures to achieve the desired throughput. CO2 dissolves in “free water” leading to the formation of carbonic acid. Both the Dynamis and Ecofys specications recommend a maximum water level of 500 ppm to avoid precipitation of a separate water phase.1 9. Alternatively. more booster stations would be required at shorter intervals to keep the pressure sufficiently high to maintain a dense-phase ow. O2 and CH4) to different levels (1%. the presence of impurities opens out the range of pressures where vapour and liquid CO2 exist in equilibrium. Firstly.3 20 8. carried out a cost-benet analysis to determine the effect of removing typical non-condensable impurities found in anthropogenic CO2 (N2. This type of corrosion is termed “sweet corrosion”.2 Impact of impurities on pipeline capacity and operating pressure. Ecofys have also produced CO2 transport/storage specications based on impurities that are likely to be present in CO2 from a coal-red power plant. gas hydrate and ice formation.2 90 772 170 132 Dodan Field Sheep Mountain EOR EOR 1983 1983 19.467 To account for increased pressure drops. 2014.3 7. although a higher limit of <10% may be acceptable for short distances.3 1 5 803 350 278 180 160 328 186 165 170 — — 186 & 204 McElmo Dome Bravo Dome Denver City Hub Gas manufacturing plant Separation from natural gas Gasication Plant EOR EOR EOR EOR Storage EOR 1984 1984 1985 1986 1996 2000 1.7 17 153 185 100 Separation from natural gas Separation from natural gas Storage Storage 2004 2006 Table 7 Typical entry specification for CO2 pipelines serving EOR operations635 Constituent Specication Reason CO2 N2 Hydrocarbons H2O O2 H2S Glycol Temperature >95% 4% 5% 480 mg m3 10 ppm 10–200 ppm 0.0 0. 7. accidental ingress of water may occur due to a malfunction at the gas conditioning facility or during a maintenance shutdown. which has been identied as the main factor inuencing corrosion. are the most problematic as these impurities open out the range of pressures above the vapour liquid equilibrium boundary of pure CO2. BP Statoil USA USA USA USA Norway USA & Canada In Salah Sleipner Algeria Norway Length [km] Pressure [bar] Source Purpose Start year 4. 11. O2. such as H2S. Downloaded on 05/11/2015 11:56:07.4.3 The role of impurities in pipeline corrosion.468 They found that limiting the amount of noncondensable compounds to <4% was optimal in terms of balancing gas treatment and compression costs. particularly at conditions close to the vapour–liquid equilibrium boundary. The presence of impurities with lower critical temperatures and pressures than CO2 enhance pressure and temperature drops whilst impurities with higher critical temperatures and pressures. Internal pipeline corrosion issues are primarily caused by the presence of an aqueous phase.4.467 Capacity [Mt per year] Pipeline Operator Location Canyon Reef (SACROC) Bati Raman Sheep Mountain North Cortez Bravo Central Basin Bairoil Snøhvit Weyburn Kinder Morgan USA Turkish Petroleum BP AMOCO Turkey USA Kinder Morgan Kinder Morgan Kinder Morgan — Statoil North Dakota Gasication Co. adding more booster station substantially increases pipeline infrastructure costs.. CH4. Pressure and temperature drops within pipelines are also affected by the CO2 composition. H2. However. and in any case. Impurities affects the physical and transport properties of dense-phase CO2 in a number of ways. this option is not feasible for subsea pipelines.466 As a consequence. increasing gas treatment energy and infrastructure costs. SO2 and NO2. causing notable corrosion in the absence of a distinct aqueous phase. The published research concerning hydrate formation in CO2 transport systems is limited.475 This journal is © The Royal Society of Chemistry 2014 . below which corrosion and other water related issues are deemed negligible. Furthermore.4. which react with water to form sulphuric or nitric acid. It has also been reported that the presence of CO in CO2–H2O mixtures can cause transgranular stress cracking corrosion.473 On the other hand.5 Dening water level specications for CO2 transport. in which water is rst removed down to 400–500 ppm using standard vapour–liquid separator drums.471 This is due to formation of a protective iron carbonate (FeCO3) product layer/ scale that precipitates out of the aqueous phase once it becomes supersaturated with iron. however. the presence of water may also lead to operational problems concerning gas hydrate and ice formation. At partial pressures <0.. H2S interacts with carbon steel in the presence of an aqueous phase to form iron sulphide. published research concerning the effect of impurities on the water solubility of densephase CO2 is very limited. Energy & Environmental Science A reasonable amount of work has been published on the corrosive properties of CO2–H2O systems at conditions relevant to natural gas pipelines. NH3 and 160 | Energy Environ.472 Of particular concern are SOx. and steel composition used by different research institutions.470 The primary cause of these discrepancies is most likely due to the differences in the ow rates. The presence of other impurities complicates matters somewhat as certain impurities will interact in the presence of an aqueous phase to enhance. followed by secondary drying on regenerative amine or glycolbased absorption columns. exposure time. Furthermore. Gas hydrates are solids with similar properties to ice that can cause blockages in the pipeline and compressors. however. appeared to be much less mobile and did not cause signicant corrosion in the absence of an aqueous phase. thus enhancing the induced corrosion rate.0035 bar. steel composition and exposure time. The solubility of FeCO3 is increased at the lower pH values.474 whilst H2S has the opposite effect. glycols are commonly used corrosion inhibitors in natural gas pipelines. material-to-water surface areas. corrosion rates are initially fast but decrease with increasing exposure time.463 To meet these specications.474 Further work is required to determine the effects other common impurities have on gas hydrate formation.4. in the case where a protective layer has formed. Investigations into the corrosion mechanisms have found that under stagnant conditions. rates are much lower due to the rapid precipitation of a protective FeCO3 scale. although the literature is not in general agreement. 2014. which could lead to severe localised corrosion.475 Rogers and Mayhew dened the threshold water vapour limit.476 Corrosion data from 12 years of operational experience on the SACROC pipeline showed that corrosion rates were limited to between 0. the extent of hydrate formation is minimal if water levels are controlled in line with industry accepted standards.469. More work is required to investigate the effects of anthropogenic CO2 impurities on corrosion and the water solubility of dense-phase CO2 at a greater range of conditions relevant to CO2 transport. water vapour content. in which CO2 is considered fully dehydrated. the presence of basic impurities such as glycols. H2SO4 on the other hand. rendering the formation of an iron carbonate protective layer unlikely. H2S at partial pressures >0. O2 will also react with FeCO3 scales to form oxides and hydroxides which are not protective. found that HNO3 and HCl were the most mobile in supercritical CO2. causing the highest corrosion rates.463 At present. including pressure. Impurities may also affect the solubility of water in CO2. Corrosion rates are dependent on the operating conditions. The presence of other impurities will also inuence corrosion rates. However. It is generally reported that hydrates can form at CO2 pipelines conditions. Corrosion can still occur in the absence of a distinct aqueous phase. forming a protective layer that inhibits further corrosion. Product layer formation is inhibited under free owing conditions as mobile aqueous phases are less likely to become supersaturated with iron. will act to further reduce the pH of any aqueous phases that have formed. Current industry-accepted water level specications typically range between 288 and 480 mg m3 (150–250 ppm). These acids along with other acidic impurities that may be present in anthropogenic CO2 such as HCl (a common impurity in ue gases from coal power stations).View Article Online Published on 13 September 2013. 11.5 mm year1 by imposing a <50 ppm water level entry specication. a two-stage drying process is required. primarily via sulphide stress induced cracking (SSIC) and hydrogen induced cracking (HIC). even at very low water vapour contents of <200 ppm.463. temperature. Corrosion rates as high as 20 mm per year have been reported for carbon steel exposed to water-saturated CO2 at relatively high temperatures and pressures. or in a few cases hinder.5 and 2. as <60% relative humidity. Sci. the frictional forces of the owing gas are likely to cause destabilisation or removal of the protective lm.477 Others have dened threshold water limits between 300 and 600 ppm. corrosion and scale formation is most likely due to the formation of residual or transient aqueous phases. A few accounts suggest that the presence of CH4 and other hydrocarbons reduce the water solubility of CO2. determined that hydrate formation in a pure CO2–H2O system could be avoided by limiting the water content to <250 ppm at conditions of 2 to 30 C and up to 200 bar. Experience from the petrochemical industry has found that H2S will also cause corrosion. 7.4 Gas hydrate and ice formation. In fact. 130–189 Review amines such as MEA will have the opposite effect on the pH of an aqueous phase and thus hinder corrosion. NOx and O2. Downloaded on 05/11/2015 11:56:07.465 As is the case with FeCO3. ow rate.471 Ruhl et al. In addition to corrosion. or stabilised aqueous surface lms. however.463 Chapoy et al.475 but many operators are opting for an even more conservative specications of <50 ppm. with different authors reporting signicantly different corrosion rates at quite similar conditions. internal corrosion within a CO2 transport system. Cracking corrosion is particularly problematic as it can lead to material failure within a timescale of days. there is far less published research at conditions relevant to CO2 pipeline transport.0035 bar can cause “sour corrosion” (or sour cracking). In this case. 11. FeS can precipitate onto the surface of the carbon steel. sulphuric and nitric acids can form in the vapour phase. Fig. Review Kinder Morgan. a 400–600 ppm water level limit seems appropriate. making in situ monitoring and cleaning of CO2 pipelines very difficult. where the CO2 dissolves in brine—this CO2-laden brine is dense and tends. where the minimum water solubility of densephase CO2 is 1500 ppm. or sections of the pipeline and compressors where there is a risk of aqueous phase formation or water ingress. As the blistering worsens. the costs are greater and degradation is not eliminated completely. 12. The injection has to be carefully monitored and controlled to prevent excessive rises in uid pressure that could fracture the rock and produce leakage pathways to the surface. CO2 has very different properties than oileld uids. The main research in the storage area has been principally devoted to three types of study: investigating in detail the different trapping mechanisms outlined above. There are signicant engineering challenges to ensure that the injected CO2 remains in the subsurface for hundreds or thousands of years. depleted oil and gas elds. Capillary trapping is a familiar concept in petroleum engineering: when water is injected to displace oil. H2S and CH4. while CO2 storage itself has been successfully implemented at several sites. corrosion-resistant alloyed steel would be more appropriate. Alloyed steels. While this is bad for hydrocarbon recovery. the same physical process is advantageous for CO2 storage: here. which in the case of seals could lead to rapid release of CO2 into the surrounding atmosphere. are much more expensive than carbon steels. Downloaded on 05/11/2015 11:56:07. water level specications for ship transport will be less exible owing to the lower operating temperature. Furthermore. understanding through analytical or simplied models the likely migration of CO2 injected into the subsurface. several tens of Mt of CO2 will be injected each year. 13 illustrates this process schematically:480 at the regional scale. It diffuses into the polymer. This is uncertainty in the quantication of storage potential. more durable polymers such as Teon and Viton can be used to reduce the problem. where around 1 Mt per year of CO2 separated from produced condensate hydrocarbon has been injected each year since 1996. CO2 injection is routine in the oil industry for improved recovery with many projects around the world. blistering the material. leading to a debate in the literature—based on direct contact angle measurements of CO2-brine-mineral systems—over the potential effectiveness of this trapping mechanism. such as valves. 130–189 | 161 . There are four principal mechanisms by which the CO2 remains underground: physical trapping below impermeable or low-permeability rock. typically around half of the oil remains underground. however. Operational experience to date. leading to a plume in the subsurface that will extend many km. components may fail. offshore in the Norwegian North Sea. species a maximum water level of 640 ppm. the principal storage sites are saline aquifers. dense-phase CO2. Fig. in the conrmation of outline assessments to a standard suitable for investment. so that a storage site can be transferred to government as a low-risk proposition for longterm care and maintenance. to avoid the payment of a carbon tax. The best publicised example is at Sleipner. trapped in the pore space. 7. orings.4. while oil and gas elds offer the economic incentive of additional hydrocarbon recovery when the CO2 is injected. and detailed assessments of safe storage capacity in different geological and industrial settings. The CO2 is This journal is © The Royal Society of Chemistry 2014 Capillary trapping and multiphase ow 12. Water level specications will most likely remain at <50 ppm to avoid gas hydrate and ice formation during compression and liquefaction. the largest CO2 pipeline operator. Furthermore. However. Further research is required to develop polymeric materials and lubricants that are resistant to the super-solvent effects of supercritical CO2. and capillary trapping where—at the trailing edge of the CO2 plume—CO2 can be trapped as pore-space bubbles in the pore space. capillary and dissolution trapping lead—over time—to increased storage security. Trapped CO2 Energy Environ. has demonstrated that carbon steels are suitable pipeline materials for transporting dry. mineral trapping. At the small scale. it is likely that more conservative water level requirements may have to be specied when transporting CO2 containing high concentrations of NOx.476 11.479 For wet or sour service. and nally the fail-safe retention of CO2. 14 shows the results of micro-ow experiments at typical aquifer storage conditions (9 MPa uid pressure and a temperature of 70 C) where the CO2 is a supercritical uid. which expands when the pressure is reduced. the tracking verication and monitoring of injected CO2.1 12. CO2 storage poses a great deal of uncertainty. so their use should be minimised to keep infrastructure costs down.View Article Online Published on 13 September 2013. such as shale. where CO2 reacts with the host rock precipitating carbonate. dissolution trapping. Supercritical CO2 is known to be detrimental to polymers and lubricants used in pipeline components.459 Alternatively. Rather than attempt to list this vast literature in a very brief overview. to sink through the storage aquifer.. In the period up until 2008. there were only two instances in North America where smart pigs survived in situ monitoring and/or cleaning operations in CO2 pipelines. The polymeric components used in smart pigs are also affected. we will highlight some important work on these topics to illustrate recent activity and highlight the progress that is being made towards the understanding and design of effective CO2 storage. however.478 However. which amounts to over 40 years. Geological storage of CO2 by injection into deep porous rock While CO2 capture is likely to represent the major cost—in both money and energy—of the whole CCS process.465 Considering water can be removed down to 400–500 ppm in vapour–liquid separator drums. this is well below the 60% relative humidity threshold at typical pipeline operating conditions (0–50 C and 85–200 bar). CO2 could be trapped in the pore space as it migrates and is displaced by brine.1.6 Material considerations. and deep coal seams. Most assessments of storage capacity consider that saline aquifers have the largest storage potential. slowly. Energy & Environmental Science injected at high pressures deep underground.1 Pore-scale properties. 2014. Sci. gaskets and coatings. The more concentrated natural CO2 deposits can produce additional information. Energy & Environmental Science A schematic of CO2 storage and trapping mechanisms. These results have been conrmed by traditional core ood experiments on larger rock samples. 13 Fig. 7.482 It shows the relative permeabilities for CO2 injection (CO2 displaces brine) to some maximum CO2 saturation. Both processes prevent the escape of CO2 to the surface. This can be as pure CO2 gas. The curves have a zero value even for finite CO2 and brine saturations. The trapped CO2 ganglia in three dimensions are shown in (c). Capillary trapping (A: residual CO2 in the pore space at the scale of around 100 mm) and dissolution (B) are illustrated here. but also the multiphase ow of CO2 in the presence of brine that is important when attempting to predict and design CO2 injection. This journal is © The Royal Society of Chemistry 2014 . or as CO2 mixtures within methane. The effectiveness of long-term storage is controlled by limiting the pressure increase to avoid fracturing of the rock that could lead to leakage. leaving a trapped saturation of CO2—that is. environmental and Fig. Sci. It is not just the amount of trapping.View Article Online Published on 13 September 2013. The CO2 and the associated pressure increase has a footprint underground that may extend 100 km or more. are leakage rates. but it cannot escape. Capillary trapping occurs at the trailing edge of the CO2 plume.. The experiments conrm that indeed a signicant fraction of the pore space (25% in this case) can contain disconnected ganglia of CO2 surrounded by water that cannot move further. This limits the spread of CO2 in its own phase.481–483 Over time the CO2 may dissolve. Fig.480 Here extensive storage of tens of Mt of CO2 per year from several power stations and other industrial plants is considered. indicating trapping. 15 Relative permeability curves – the fractional conductance for flow – as a function of brine saturation. These curves are used to predict the movement of CO2 at the large scale in the subsurface. A collection of trapped clusters. where brine displaces CO2. The CO2 is injected through an array of wells that penetrate deep in the subsurface. 12. 2014. Storage of CO2 has occurred in many natural situations. 162 | Energy Environ. 15 shows a compilation of relative permeability measurements of a supercritical CO2– brine system. followed by CO2 displacement by brine. and the interplay of trapping mechanisms at the small scale. is shown in (b). The segmented image. This is quantied through the relative permeability: it measures the ow conductance of a phase as a function of the fraction of the pore space it occupies (the saturation). this mechanism severely limits the spread of the CO2 plume. the relative permeability of CO2 is zero even though the CO2 saturation is nite. requiring separation for commercial purposes. used to identify the fluid phases.482 A compilation of experiments are shown for CO2 injection into brine to a given saturation.2 Natural analogues. over 104 to 106 years. CO2 (light) and brine (dark). Particular aspects which can benet from this long-term view. The colours indicate the size of the clusters. which can inform predictions on the performance of engineered CO2 storage. illustrating the wide range of size and shape is shown in (d). 14 Pore-scale images of trapped CO2 in sandstone. Downloaded on 05/11/2015 11:56:07.1. or densephase CO2. followed by displacement of CO2 by brine. Fig. which grade into associated CO2 with natural gas deposits.571 (a) This is a two-dimensional cross-section of a three-dimensional image showing in grey scale the rock (grey). 130–189 Review is imaged in the pore space with a resolution of approximately 10 mm. predictive assessment of the extent and speed of CO2 movement in the subsurface. At the eld scale. Dissolution occurs throughout the plume: the CO2-saturated brine is dense and sinks. These curves can then be used for a quantitative. notably Norway.487 An important stabilisation mechanism is for CO2 to come into contact with large volumes of formation water. Assessment of the storage capacity takes into account the factors mentioned above: the likely increase in pressure. USA assessments typically assume that all available storage volume can be utilised within a reservoir. and so form secure retention for tens of millions years. and chemical interactions with reservoir and caprock. the excess human death rate is extremely low. The rst step towards CO2 storage for many nations has been the evaluation of potential storage volumes beneath their national territory. onshore southern Italy and Tyrrhenian sea adjacent to Sicily. Sci. which also tend to reduce proposed storage capacities.486 CO2 uids in oil elds do not react strongly with mud caprocks. and many Mt in large regional aquifers in areas with signicant industry and fossil-fuel power generation. these can oen remain out of equilibrium for several million years.. 2014.480 Analytical models have been combined with regional geological models to estimate a total storage capacity of over 100 Gt in the continental US.484.490 The current information thus shows that geochemical factors in reservoirs and caprocks for CO2 storage need not be adverse. some European states consider only discrete closed structures and ignore the intervening connections of saline formations. followed by USA and Canada.2 Regional assessments of storage capacity To make a signicant contribution to reducing atmospheric emissions. but have reduced its upper limit by assuming generic efficiencies of CO2 emplacement within the reservoir.488 In a worst-case scenario. Consequently different states currently approach storage differently. Fig. Downloaded on 05/11/2015 11:56:07.485 However. These initial estimates demonstrated much more than adequate storage capacity for the next 100 years of emissions. and can tend to optimism. at less than one in 30 million per year. 130–189 | 163 . This journal is © The Royal Society of Chemistry 2014 Energy Environ. greatly enhancing dissolution for long-term stability. CO2 can leak slowly to the surface for many millennia489 without monitoring or safety precautions.View Article Online Published on 13 September 2013. These are normally incorporated into analytical or numerical models to estimate how much CO2 can be safely stored and the likely extent of CO2 migration in the subsurface. The methodology combines an assessment of both the storage capacity and how fast the CO2 can be injected. It is likely that global nance will require improved standardisation of denition for reserves. Some brief highlights of this expanding literature include that CO2 uids do react with sandstone reservoirs.1 Dening the storage reservoirs and storage complex. these are the Colorado Plateau of USA. Prominent leaders in such assessments have been Australia. and are now being rened through second and third generation compilations.2. and subsequently an overall appraisal for all European-27 states. Energy & Environmental Science As an example.480 A total capacity of over 100 Gt is calculated. have now started to undertake dynamic reservoir simulations. the actual capacity in CO2 storage reservoirs at present remains essentially unvalidated. and the North Sea. By contrast. Three geographical regions are providing most of the additional information. Around such natural leakage sites. 12. Review human health impacts at the surface. if factored into site choice. albeit slowly via oxidation–reduction pathways. which avoid fracturing caprocks. None of these assessments consider engineering interventions to Fig. However. and by calculating maximum permitted injection pressures. 16 A US-wide assessment of CO2 storage capacity. 7. 12. it will be necessary to store several Gt of CO2 each year worldwide. sufficient to make a major contribution to mitigating CO2 emissions in North America. Several European states have calculated their entire storage volume. There is no standardisation of these methods. 16 shows the estimated storage capacity in large regional aquifers in the continental US. Some states. as we discuss next. CO2 movement and trapping processes. to enable valuation of assets. This range coincides with “good quality” hydrocarbon caprocks. for example.2. the UK has taken a centralised approach where the rights to all pore space are managed for the Crown Estate. it is claimed would cause multiple storage sites to rupture and leak CO2. different regions are bound by ancient mining rights. From a practical point of view. perfect containment of pressure by reservoirs below ground is exceptional. These are on subsurface pressure. it still remains very unclear how large-scale CCS storage reservoirs may be evaluated and tested. although the longest duration project is at Rangely and the best-known project for CCS is Weyburn in Saskatchewan.491 Regulators and lawyers are concerned to avoid damage or trespass into adjacent subsurface property. although pressure buildup needs to be specically managed. it is likely that much more intense scrutiny of candidate site information on storage will occur. As the CCS endeavour starts to enter into development of the rst pilot projects. and may cost many tens.497 Clearly this can take 5 or even 10 years. Initial experimental projects. and assessing the interaction of multiple injections into the same reservoir remains a problem with no clear solution. For example. Additional complexities can arise when licensing and regulation activities collide with natural subsurface geometries of reservoir and seal. Energy & Environmental Science increase storage tonnages. Firstly. These earthquakes. is likely to be the rate determining step for CCS worldwide. By contrast. as there are numerous unpublished examples of commercial investigations worldwide for CO2 storage which have failed to meet the required performance targets and have resulted in the cancellation of project developments. around each commercial injection location. in Germany. CO2 has been injected into the subsurface for many decades for the purpose of improving oil recovery.View Article Online Published on 13 September 2013. Adding large tonnages of CO2 into the subsurface usually implies adding additional uid volume. federal European law has not helped.3 CO2-enhanced oil recovery. However. and in a conned reservoir or aquifer. the European CCS Directive allows denition of a much greater subsurface volume.2 Challenges to the concept of large volume storage. Mississippi and Louisiana. induced seismicity. with a further nine planned to be This journal is © The Royal Society of Chemistry 2014 . 7. In many states of the USA. Zoback and Gorelick496 inferred an increased risk that seismicity will be induced. Unplanned CO2 migration from a European Emissions Allowance reservoir need not be a leakage from a CCS Directive complex. Cavanagh. consisting of the dened reservoir and caprock. However. of millions of dollars. in that the European Emissions Allowance Directive denes a very local storage site. Sci. In a related piece of modelling prediction Cavanagh495 states that the boundary conditions of permeability of the enclosing seal are important and should lie between 1018 m2 for pressure bleed-off and 1020 m2. which although are expected to be accurate. This remains a real problem. These legal approaches will need to be harmonised during the progress of early CCS injection demonstrations. 164 | Energy Environ. high-quality investigations of saline aquifer regional geology will be required before any licensing can occur. 2014. By contrast. so provide some information on subsurface behaviour but less as an analogue for the CCS techno-economic system. such that even the federal state cannot interfere. with impermeable boundaries. Existing test injections of CO2494 show that 19 of 20 pilots have not experienced adverse pressure buildup with the exception of terminating injection at Snøhvit. they are—as we have commented already—still unvalidated. as mentioned in the beginning of this section. and that the rate of pressure dissipation over a large area is the important factor. we discuss the pressure management of subsurface injection. even though engineering optimisation will be an essential part of any commercial project. probably hundreds. Countering this. (iii) that a pressure anomaly can be managed by water production. (iv) that physical leakage of CO2 as a consequence of seismicity would only occur if the tremor site coincided in space and depth with the physical CO2—which is very unlikely. Most of these 70 or so projects have been and are supplied with CO2 from natural accumulations of volcanic derivation. Economides & Economides492 suggest that nite poor volumes below ground will limit CO2 injection to 1% of pore space whilst also reducing rates of injection. this has been widely critiqued on the basis that (i) licensing of a storage site before injection and monitoring aer injection will eliminate known tectonic sites and (ii) will detect anomalous small tremors before buildup to larger events. this may be resolved by the acquisition of rights to pore space utilisation across surrounding properties.2. or will the much greater geographical area of pressure increase be regarded as adversely affected? Different European states have different historical approaches. linked to suitable business models and regulatory permissions.. Innovation is badly needed in the technical evaluation of storage. This is overwhelmingly in the USA in southern states of west Texas. 130–189 Review that leads to pessimistic outcomes. or less to retain pressure. Four CO2 injection projects are currently in operation. Blunt and Haszeldine493 point out that. 12. that will inevitably tend towards an increase of uid pressure. Determination of adequate storage. although it remains unclear if this will be to protect against a simple case of physical CO2 movement. such investigations could act as a terminal slowing of the rollout for commercial CCS. whilst also attempting to ensure maximum certainty in identifying injected CO2. by systematic extraction of groundwater. This causes some analysts to propose that largescale. even on industrial scale. Downloaded on 05/11/2015 11:56:07. inevitably choose high-quality reservoirs. Although the practise of injecting dense-phase liquid CO2 is well established and although the assumed progress is towards multi-million-tonne-per-year injection sites—some objectors still raise potential uncertainty in fundamental processes. by injection of large volumes of CO2. suitable for the CO2 tonnages envisaged during the entire power-plant lifetime. especially onshore. That will start to provide information to test the predictions made during generic assessments of regional storage formations. If pessimistic assumptions are made of compartmentalised storage reservoirs. If undertaken in a failsafe and stage-gated process. and reservoir evaluation. aquifer contamination. assessing the regional impact of injection. (v) the pressure pulse anomaly will decay within 50 years from the time of peak CO2 injection rate. which can contain multiple layers of reservoirs and multiple seals. 12. Even with these practical difficulties of emissions offsetting. or reinjected to promote capillary trapping. Storage is considered permanent so no post-storage monitoring would be required. until the end user undertakes combustion. using conventional injection and production plans. Over time— with capillary.500 Carbonation of magnesium and calcium silicate ores occurs naturally (known as natural weathering). Of these.457. By contrast in Europe these additional emissions will be explicitly counted as part of the carbon budget and if CO2 emissions credits are to be claimed. However. so the theory is that the process could be utilised to produce useful energy if heat is released at high enough temperatures. efficiently and securely. such projects have two signicant disadvantages: the rst problem is that CO2-EOR objects fall under industrial legislation. connected to multiple storage sites which will reach their full potential aer the additional oil production is exhausted. it may still be worth undertaking CO2-EOR as a stepping stone to rapid building of large numbers of capture plants connected to pipeline networks. More work is needed on how to provide sufficient condence in storage site evaluation. particularly serpentine. and such projects may fund the building of pipeline transportation networks for CO2. CO2 storage is not a passive process but one that with responsive monitoring and engineering can be achieved at scale. with storage security increasing over time. however. making up approximately 2.498 In North America the additional oil is not conventionally regarded as producing an emission.500 However.and Ca-silicates is still exothermic. DH ¼ 118 kJ mol1 (14) 13. The development of CO2-EOR projects may accelerate the development of efficient capture engineering but will do little for net CO2 reduction over the life cycle of a project.0 and 2. Even if natural seals are breached. Diverse objections raised against storage.3 Conclusions (CO2 storage) The overwhelming consensus is that large-scale storage of CO2 is feasible. MgO and CaO are the most naturally abundant of the alkali and alkaline earth metal oxides. This can have a benet in that such projects encourage and enable the development of efficient and low-cost CO2 capture technology. Downloaded on 05/11/2015 11:56:07.1 Mineral feedstocks.499 In addition. DH ¼ 179 kJ mol1 (13) MgO(s) + CO2(g) / MgCO3(s). consequently there is no mandate to undertake details or extensive CO2 monitoring through the lifetime of the project to demonstrate and predict secure long-term retention. The primary purpose of those projects is to produce oil rather than to dispose of CO2. new wells can be drilled. because oil production is regarded as free of emission. there is a need to produce greater certainty in the fail-safe retention of CO2. such as serpentine and olivine. then monitoring validation of CO2 storage will be required. 3 tonnes of CO2 produce one additional barrel of oil. although to a lesser extent. are considered the most important mineral carbonation feedstock.1 Background Ex situ mineral carbonation is a suggested CO2 sequestration option for geological storage. 2014.View Article Online Published on 13 September 2013. Improving the carbonation kinetics is one of the most signicant challenges facing the development of a commercial mineral carbonation process. the carbon budget overall becomes conicted by double counting. in nature. to positively inform the process of starting a CCS power-plant development. CO2 sequestration via ex situ mineral carbonation 13. Review operating by 2016.501 Furthermore. Mgsilicates. suggesting uncontrolled pressure increase. Additionally.457 Mineral carbonation also provides an option for storing CO2 at locations without access to geological storage sites. If injectivity is poor. then leakage rates in natural examples are slow and impact at the surface is small. There is enough alkaline earth metal oxide-containing material on earth to sequester all of the CO2 that could ever be emitted from fossil fuel use. or induced seismic tremors leading to extensive This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science leakage. extracting and processing the large amounts of raw material required for an industrial scale operation is very energy intensive.. They are widely available. and rock deposits bearing these minerals tend to contain them in high concentrations (typically containing in the region of 30–60 wt% MgO).501 The carbonation of Mg. 12. dissolution and mineral trapping—storage becomes more secure and the CO2 less likely to escape. The process involves carbonating materials containing alkali or alkaline earth metal oxides or hydroxides.1. CaO(s) + CO2(g) / CaCO3(s). they are less reactive than their corresponding metal oxides and the kinetics under ambient conditions are far too slow to form the basis of a commercial process. 7. which itself will produce CO2 upon combustion. are potential difficulties which can be managed with known techniques. 13. Second. viewed from the objective of CCS. which is shown both by trapping processes measured at laboratory scale and by calculations from natural analogues. MgO and CaO do not exist as binary oxides and are typically bound up as silicates. Benets from those projects may be a legacy of pipeline to access abundant proven storage sites. It is wrong to think of the CO2 as having some typical storage time or leakage rate: the (low) risk of leakage occurs mainly during the injection period and declines with time as pressure dissipates and the CO2 becomes less mobile.1 mol% of the earth’s crust respectively. Sci. CO2 storage can be engineered to deal with potential problems. xing captured CO2 as thermodynamically stable and environmentally benign carbonate minerals (eqn (13) and (14)). It is estimated that 3–8 tons of mineral needs to be mined (and ground to <75 mm) to store the Energy Environ. about 75% intend to undertake CO2-EOR where. The main concern is to ensure that the uid pressure does not increase sufficiently to induce fracturing. available to be used to release additional fossil fuel. the carbonation process is exothermic. 130–189 | 165 . and to ensure that the mobile CO2 does not nd a permeable path to the surface. water can be abstracted from the subsurface to relieve pressure. CO2 captured from combustion of coal or gas at a power station cannot be regarded as free from emissions. and iron oxides). On the basis of these calculations. However.2 Indirect mineral carbonation. 7. together with the low value of the produced material will make this an exceptionally challenging proposition.1. A comprehensive analysis of potential applications for mineral carbonation products is provided by Sanna et al. the lifetime in which CO2 is removed from the carbon cycle will vary: some uses. have a longer term.4 Future scope. mineral carbonation may also serve as a means for treating environmentally hazardous waste streams. They are cheap and widely available. In fact. their use helps to address issues and costs associated with waste disposal. if CO2 mineralisation technologies are to offer the kind of CO2 storage capacities required for climate change mitigation applications. CCS on the other hand requires market intervention by governments through the application of strict penalties or economic support and subsidies to achieve the same result. they require minimal preparation.1.505 13. an order of magnitude higher than the current cost of geological storage at 5–10 US$ tCO21. it is likely that CO2 mineralisation of waste streams will nd niche applications for hazardous waste remediation and as a means for some industries to produce valuable by-products from their waste whilst reducing their CO2 emissions. amounting to around 232 Mt per year. Alkali and alkaline earth metal-rich waste streams such as iron and steel slags. which are of commercial value when obtained at sufficient purities.g. 14. mineral carbonation reduces the mobility of heavy metal trace elements such as Pb. Over the last few years. whilst others.3 Carbonation of alkali waste streams.510 13. In some instances. wide-scale deployment would saturate any potential high value market. 2014.2 Current status of CDR technology Despite the fact that CO2 is a renewable.457 13. or fuels (CO2-to-fuels).503 A feasibility study carried out by O’Connor et al. For example. Furthermore. Downloaded on 05/11/2015 11:56:07. Furthermore. particularly if the process generates marketable by-products. with only a few commercial processes currently using CO2 as a raw material (Table 8). there has been a growing interest in developing indirect aqueous carbonation processes where metal extraction and carbonate precipitation is carried out in two or more stages. CDR can result in some permanent storage and removal of CO2 from the carbon cycle (e..507 Pilot-scale testing of this technology is likely to follow in the near future. and low-value applications will not support a signicant market. conditions can be optimised for each stage individually.1 Carbon dioxide re-use Background Carbon dioxide re-use (CDR) is a purported alternative to storage that involves the production of saleable products from captured CO2. they tend to be much more reactive than naturally occurring Mg and Ca-silicates. sequestration costs alone were estimated at 50– 100 US$ tCO21.508 However. Furthermore. However. economically feasible processes utilising naturally occurring Mg. like y ash and indeed most other potential waste-derived feedstocks. are very short term (days to months). lowcost and low-toxicity C1 feedstock. therefore. the use of CO2 as a technological uid or as a precursor for fuel production). Most of the current demand is met by naturally derived CO2 with only 40 Mt obtained from anthropogenic sources of which 70% is used for EOR purposes and This journal is © The Royal Society of Chemistry 2014 . particularly if the technology reaches the demonstration or early-stage industrial deployment phase. in most cases. Whilst indirect processes are more complex.506 CO2 mineralisation can also be used to neutralise highly caustic waste streams such as red mud produced from bauxite processing for aluminium production. and the energy required to grind materials to the required size distribution. CDR includes the use of CO2 as a technological uid and as a reagent for the production of chemicals (CO2-tochemicals). CDR will result in re-emission further down the line (e. ash from fossil fuel combustion. such as its use as a precursor for plastics.504 estimated that an industrial-scale mineral carbonation operation based on the NETL process would impose a 30–50% energy penalty on the power generation process.3 Gt per year. and in most cases. Sci. However. 14. In a few cases. The primary advantage of CDR compared with CCS is that its end product is of value. 75% of this penalty was attributed to grinding the feedstock to <37 mm. 14. the argument that CDR will meaningfully increase the price of CO2 fails to take into account the vast supply of CO2 and the comparatively small demand for CO2. which can leach into the surrounding environment aer disposal.502. widely available.View Article Online Published on 13 September 2013. however. Cd and Ni found in some wastes. The combined system of CO2 capture with CO2 re-use is typically referred to as carbon capture and utilisation (CCU). plastics (CO2-to-plastics).1. enhanced oil recovery or mineral carbonisation).and Ca-silicates must be developed.437 O’Connor’s costings are still used as the official best-case scenario estimated costs for mineral carbonation by many of the important organisations and agencies advising on climate change and mitigation strategies. Further development of ex situ CO2 mineralisation processes that utilise waste feedstocks (or 166 | Energy Environ. Energy & Environmental Science CO2 released from the combustion of 1 ton of coal in a coal-red power plant. waste concrete and cement kiln dust offer a number of advantages as feedstocks for CO2 mineralisation applications. current industrial demand is relatively low. 130–189 Review wollastonite) and generate valuable by-products may help to progress technologies to the pilot and demonstration phases.505 The sale of such materials might help to subsidise process costs.g. In the latter case. such as the IEA and IPCC. the use of CO2 as a precursor for some plastics may result in the CO2 being xed away from the atmosphere for decades and can. the CO2 storage potential of iron and steel slags is low—estimated at up to 170 MtCO2 per year509 compared with total global CO2 emissions from the iron and steel sector of 2. silica. incentivising development and deployment of CO2 capture technologies.437. be considered a form of storage. indirect processes oen generate separate streams of the different reaction products (typically magnesium or calcium carbonate. such as the use of CO2 as a fuel precursor. It has been argued that increased deployment of CDR processes will therefore drive up the market price of CO2. Urea has been produced from CO2 on an industrial scale for many years and currently represents the largest market for CO2 outside of EOR.511 This. CO2 is also used as a coolant in air conditioning units.520. such as by drilling additional targeted and deviated bore-holes. and alternative. cheaper options for maintaining oil production in depleting reservoirs. which have current global markets of several hundred kt per year515–517 and 4 Mt per year3 respectively. BP and Norsk-Hydro and have failed commercial hurdles due to high offshore platform retrot costs.520 Given that between 0. as a fumigant. such as unconventional gas and tight oil.3 Table 8 Current CO2 consuming industrial processes3. 7. Over recent years.6 Mt per year.. Review Energy & Environmental Science another signicant fraction used for urea production.6 14 30 4 10 8 50 — 0. unclear and illdened regulations governing EOR activities.514 Furthermore. most of the CO2 used for EOR is currently not stored. According to the International Fertiliser Association. for controlling the pH of process water in water treatment applications. Of particular interest are alkylene carbonates and polycarbonates.511 At present. the future of EOR is uncertain.513 At present. CO2 has a number of commercial applications as a technological uid. 2014. Despite this.3 Energy Environ.518. followed by the endothermic decomposition and dehydration of ammonium carbonate to yield urea. There are a vast amount of different chemicals that in theory could be produced using CO2 as a C1 feedstock.2. High CAPEX and OPEX costs and uncertainty over long-term oil prices.519 urea (160 Mt per year). a number of elds in the North Sea have been assessed as potential sites for EOR by Shell. This journal is © The Royal Society of Chemistry 2014 Scheme 3 Chemical transformations of CO2 into synthetic targets with large current or potential markets (adapted and updated from Mac Dowell et al. enhanced gas recovery (EGR). particularly as oil production declines in existing wells in the Gulf States. most of the CO2 used for EOR (50 Mt per year) and by the food and beverage industry (8 Mt per year) is sourced from natural CO2 reservoirs. Scheme 3 outlines a number of promising CO2-derived synthetic targets and their current global market. The overwhelming market for urea is that of the fertiliser industry. in turn. which consumes over 80% of total global urea production. The overall process is exothermic and no catalyst is required.512 The following sections provide a brief overview of the current status of CDR technology. Advanced Resources International estimated that at least 8 billion tons of CO2 could be sequestered using EOR in the US alone.2 Urea. 130–189 | 167 .521 and acrylic acid and acrylates (10 Mt per year).4 Mt per year.View Article Online Published on 13 September 2013. EOR offers one of the largest potential markets for CO2. would produce between 4 and 47 billion barrels of additional domestic resources. In a recent report. including enhanced oil recovery (EOR).2 10 8 50 232 Mt a Lifetime of storage Months Months Decades – permanent Decades Days to years Days to years Permanenta Whilst EOR offers the potential of permanent storage. 14. CO2 consumption as a consequence of urea production is around 119. the market for CO2 is several orders of magnitude smaller than the amount of CO2 released into the atmosphere each year from anthropogenic sources and approximately 60 times smaller than the amount of CO2 emitted from large point sources (14 000 Mt per year). current global production of urea is 159.75 tonnes of CO2 are consumed per tonne of urea. offshore EOR has yet to be proven.520 polyurethane (18 Mt per year).6% of the World’s proven oil reserves. many would either prove impractical to produce from CO2 on an industrial scale or have limited market potential. EOR also competes with other methods of enhanced resource production. cash ow issues.2. coal-toliquids (CTL) and gas-to-liquid (GTL) technologies. and as a green solvent (including its use in dry cleaning). there is potential for signicant growth in CO2 use and subsequent sequestration via EOR. Given that the US has only 1. enhanced coal bed methane (ECBM) and numerous food and beverage applications.1 CO2 as a technological uid. and wavering public support have all impeded deployment of EOR.3 Urea is manufactured via a two-step process that involves the exothermic reaction of liquid ammonia and dry ice (solid CO2) to form ammonium carbonate. Sci. however. inorganic carbonates (60 Mt per year). CO2 to chemicals.512 therefore minor emissions reductions could be achieved by utilising captured CO2 instead.4 55 80 119.636–638 Process Urea Methanol Inorganic carbonates Organic carbonates Technological Food EOR Total Industrial volume Mt per year Global CO2 usage Mt per year 159. Downloaded on 05/11/2015 11:56:07.522 14.735 and 0. particularly considering that the original source of energy for the production of H2 is electricity. Therefore. and discusses the continuing policy challenges which are faced. Downloaded on 05/11/2015 11:56:07. releasing the CO2 into the atmosphere. water splitting via electrolysis.3 CO2-to-fuels The production of fuels from CO2 is ostensibly an attractive goal. A recent review of costs in industrial settings deals with this subject527 and an excellent summary of recent pilot and large-scale costing data is available from the Global Carbon Capture and Storage Institute on a yearly basis. then using this to run an internal combustion engine.524 In this case. Whilst it is perhaps too early to say which set of technologies will come to dominate the eld. CO2 is the lowest energy state of any binary neutral carbon species and the ultimate product of energy-releasing hydrocarbon combustion and metabolic pathways. focusing on the power generation sector in the UK and EU. therefore. 168 | Energy Environ.3 Methanol can be produced via the catalytic hydrogenation of CO2 utilising similar conditions catalysts to those used for the production of methanol in the conventional commercial approach. and beyond. alternatively. both methods of producing methanol consume a great deal of thermal energy. generator or fuel cell during periods when RETs relying on intermittent energy sources (such as the sun or wind) are not able to meet demand. The future of CO2-to-fuels technology. a clear framework for regulating and incentivising wide-scale deployment of CCS and EOR that also addresses potential liability issues associated with EOR coupled with permanent storage needs to be established. 14. further reducing the case for increasing urea production as a means for stimulating the development and deployment of CCS/CCU technology. 15. the UK Government launched a competition for demonstrating post-combustion capture on a coal-red power This journal is © The Royal Society of Chemistry 2014 . given that the global fuels market is roughly two orders of magnitude greater than that of chemicals. Sci.528 16. Published on 13 September 2013. i. However. In the short term. Furthermore. the ‘leading role’ that the UK is taking with a package of measures intended to support CCS projects both in.526 It is not the purpose of this section to review estimated costings for different technologies. the impact will be insignicant. a third of the hydrogen is converted to water. The fuels produced could be used to re a power plant. Further work is also required to assess the feasibility and any potential deployment issues associated with EOR and permanent storage particularly at off-shore locations. these targets include syngas. the production of easy to transport fuels from CO2. only a very few synthetic fuel targets can possibly be considered viable.4 Future outlook At present. this process is inefficient.503 the storage of CO2 within urea is short. the use of hydrocarbons can be avoided by using H2 from renewable sources. combined with the use of electric vehicles is around ve times more efficient in terms of miles driven than using the electricity to produce hydrogen. since this subject is highly contestable and frequently quite subjective. of which fertiliser use is the main source. is low. increased deployment of EOR has the potential to offer the largest economic stimulus for large point sources to capture and subsequently store their CO2. since the chemical breaks down upon application as fertiliser. and the lifecycle efficiency.View Article Online Energy & Environmental Science The climate change mitigation potential of ramping up urea production is poor. The use of anthropogenic CO2 in place of CO2 derived from natural deposits will offer small emissions reductions. utilising renewable energy at a remote location (such as geothermal or solar) might prove a more convenient and cost-effective way of delivering otherwise stranded resources to market than constructing transmission lines or nding other potential uses for such resources. utilisation of CO2. CO2-to-fuels technology is far from commercial status and will have to compete with other unconventional methods of producing liquid fuels.525 This section reviews the recent history of policy support for CCS. N2O emissions. A recent history of UK and EU CCS policy In 2007. particularly when considering that H2 production via electrolysis of water is a very energy intensive process. the drawbacks with this approach are that equilibrium yields are much lower compared with methanol production from syngas. As discussed by Fennell. However.. particularly CO2 from anthropogenic sources. 2014. is exceptionally low. the energy requirements must be supplied from non-fossil sources. it is certainly the case that any CCS technology will require policy support to ensure deployment at the scale and volume required to deliver on climate change goals. such as GTL and CTL in addition to other means of storing and utilising energy such as high efficiency batteries and ultracapacitors. 7. i. When considering the energetics of CO2 activation. The idea is that the application of such technology may provide a way of storing excess electrical or intermittent electricity production.523 In addition. a signicant energy input is required to overcome the substantial thermodynamic and kinetic barriers of converting CO2 into a useable fuel. remains highly uncertain because of the inherent thermodynamic efficiency penalties. Policy design and implications for investment 15. In addition. In order for the production and use of CO2-derived fuels to contribute to climate change mitigation efforts. It has been argued503 that pumped storage of the electricity. methanol and formic acid. RETs or nuclear. the demonstration phase.e. Furthermore. together with the implications for potential investment in CCS projects. The focus reects the key role that decarbonisation of the electricity generation sector is expected to have in meeting CO2 emissions reduction goals. together with the EUwide policies to support demonstration projects. methane. 130–189 Review 14. the fuels could be used for mobile or distributed applications. although in the context of climate change mitigation.1 Introduction The preceding sections of this paper have discussed the range of CCS technologies under development. then methanol.e. correspond to around a third of anthropogenic N2O emissions. working closely with National Grid and who together form “Capture Power”. equivalent to 450 gCO2 kW h1 for plant operating at baseload. To be eligible. (3) An Emissions Performance Standard (EPS) to put an annual limit on the amount of CO2 that a plant can emit. with the UK Government citing increased costs and the inability to reach a commercial agreement as the reasons. Table 9 details projects which were shortlisted for funding by both the EU and UK CCS competitions. Review station. however. During the same year. meaning a maximum of V292–337 million for any one project. Applicants for funding from the new process must be able to demonstrate at commercial scale and be operational by 2016– 2020. the UK Government has announced the two preferred bidders for the Commercialisation Programme competition. security of supply or affordability for consumers’. Both projects are currently performing front-end engineering design studies. The EC currently anticipate that the total level of funding from the process will be between V1. 7. it was anticipated that the New Entrant Reserve funding (commonly referred to as the NER 300) would be available from the auctioning of 300 million EU ETS allowances.531 A key development was the decision to make gas red generation eligible for the competition. aiming to ‘make the UK a world leader in this globally important technology’. The level of funding available through the NER 300 process will be considerably less than was originally hoped because the market price of EU ETS allowances is well below the level envisaged when the process was set up.541 In practice this means that potential investors will tend to prefer low capital cost conventional gas-red power station projects with operating costs linked closely to electrical output. These are the White Rose project.1 Implications for investment in CCS The generic investment challenges faced by renewable energy and nuclear power plants operating in liberalised energy markets are well understood. under the rst round of the NER 300. thereby effectively prohibiting new unabated coal-red plant but new allowing new unabated CCGT plant. The combination of high capital costs and very low operating costs means that such plant are typically ‘price takers’ because once constructed. The 2010 Spending Review conrmed that Government would provide up to £1 billion for the successful project.541 CCS introduces another set of challenges because it also carries relatively high fuel and operation and maintenance Energy Environ. involving Shell and SSE. with funding for any individual project capped at 15% of the total. but on the same day as this announcement was made.5 billion. ScottishPower pulled out of the rst This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science demonstration plant competition in October 2011. It is conventional gas and coal-red plant that have the ‘price maker’ role and have the dominant inuence over electricity prices as they are generally able to remain protable over a wider set of operating regimes and pass variations in fuel costs through to consumers. At the time of writing (May 2013).529. At the same time.538 This new process was launched as a ‘Commercialisation Programme’ and involves a competition through which successful applicants will receive direct funding from the £1 billion budget and also the possibility of further revenue-based support under the CfD FiT mechanism proposed in the EMR. but this levy was later shelved. and adequately reward back up capacity to ensure the lights stay on’. (4) A capacity mechanism to ensure that there is sufficient generating capacity to meet peak demand.. These reforms were driven by Government’s belief that ‘the current market will not deliver on the Government’s objectives for decarbonisation. the UK Government launched a consultation on the EMR which set out a proposed package of policies to ‘ensure that low-carbon technologies become a more attractive choice for investors.530 Two of the applicants for the competition were awarded funding for Front End Engineering and Design (FEED) work. Sci. to be operational by 2014. one of the remaining applicants withdrew from the competition on the grounds that the economic conditions were not right. though funding is still potentially available in the second round. even if the lifetime levelised costs of electricity from higher capital cost projects are similar.533 At the EU level. through a Contract for Difference (CfD). no CCS projects were granted funding. 130–189 | 169 . Downloaded on 05/11/2015 11:56:07. it typically makes most sense to run them whenever they are physically able to do so. (2) A carbon price oor to reduce uncertainty for investors and incentivise low-carbon generation by topping up the EU ETS carbon price. an oxyfuel-based project based at Drax.View Article Online Published on 13 September 2013.539 The separate process by which the EC selected projects for funding under the NER 300 scheme continues in parallel to the UK Government’s Commercialisation Programme.535 The four key EMR mechanisms are: (1) A Feed-in Tariff (FiT) to stabilise and top-up the revenues of low-carbon generators including CCS.532 It was originally intended that funding for the further three projects would be nanced by a levy on consumer bills. almost regardless of electricity prices. transferring electricity price risk from generators to consumers. and learn about projects being considered by industry’.3 billion and V1. the UK Government reaffirmed its commitment to a further three CCS demonstration projects. In the meantime. Longer term. the CCS funding mechanism is bound up in the Electricity Market Reform (EMR) process. and completed a market sounding exercise to ‘help the department to explore workable options for the CCS demonstration project selection and funding processes. However.540 and the Peterhead project in Aberdeenshire.534 In December 2010. North Yorkshire and proposed by a consortium of companies including Alstom. Scotland.0 billion in total with a substantial fraction of this to be available for CCS projects across the EU. 2014. leaving only one remaining applicant—a post-combustion retrot to part of ScottishPower’s Longannet coal-red plant. Drax and BOC. The EMR consultation process was followed by a White Paper during 2011536 and in 2012 by a dra Energy Bill537 which set out the legislative framework for the proposals. it was conrmed that the £1 billion of public funds set aside for the rst demonstration would be ‘available for a new process’. 16. at the time expected to raise between V4. following recommendations by the Committee on Climate Change. all prospective NER 300 projects are required to secure 50% co-funding from other sources.5 and V9. coal Post-combustion. which may lead to lower load factors for some CCS plant. a carbon cost for the residual CO2 emissions which cannot be captured. With a different analytical approach.553 whilst others question the degree to which the long term CO2 storage This journal is © The Royal Society of Chemistry 2014 . Whilst the support offered through the FiT mechanism proposed in the EMR suits the characteristics of low operating cost plant such as nuclear and wind power.542 In the relatively small literature on CCS as an investment proposition.531 a view which has some support. petcoke. fuel Country Project Type.View Article Online Energy & Environmental Science Table 9 Review EC and UK CCS project shortlists Published on 13 September 2013. They 170 | Energy Environ. gas Pre-combustion. the fuel costs associated with CCS plants suggest that it may require a premium payment that is linked to those fuel costs. low-capital-cost CCGT plants. biomass Industrial application. and a potential long-term liability associated with the stored CO2. whilst lower carbon than conventional coal. as some suggest. are unlikely to deliver the level of CCS deployment that many suggest will be required. coal Industrial application. when a more coordinated approach might be more cost effective in the long run.548 a view that has some support from within the industry. It is argued by some stakeholders that with current policy there is a danger of a piece-meal build-up of pipelines. levelised costs for CCS are likely to show only small reductions over the next few decades as potential reductions in capital cost are offset by carbon price increases.543 In their 2009 paper. 2014. baseload. potentially loadfollowing plant such as CCS. particularly if. The relatively high variable costs of CCS (when compared to nuclear or wind power for example) mean that CCS plants can generally be expected to have a lower position in the electricity market merit order. Concerns over the long term liabilities associated with CO2 storage are oen raised in the context of the investment proposition of CCS. Sci. fuel Don Valley Power Project Belchatow CCS Project Green Hydrogen The Teeside CCS Project UK Oxy CCS Demo (White Rose Project) C. Others contend that the EU ETS on its own won’t lead to large scale CCS deployment. all the while questioning several underlying technical and policy premises that are necessary to ensure this goal’. both internationally and in the UK. coal. conventional CCGT. coal Oxyfuel. coal Post-combustion.549 Flannery550 contends that ‘CCS today lacks both an economically viable policy framework and a business model’. This ‘load following’ role in the UK electricity market has typically been lled by a combination of relatively new. Hamilton and colleagues546 suggest that given ‘nth of a kind’ cost estimates available and the projected value of avoided carbon emissions under the then proposed US carbon cap and trade bills. Super Critical Pulverised Coal (SCPC) plant with CCS would not present a breakeven proposition until aer 2030.545 From their analysis of CCS investments in the US policy context. gas UK Italy France EC NER 300 Reserve list Getica CCS Demo Project Peterhead Gas CCS Project Post-combustion. coal. which presents an opportunity for low-carbon. Osmundsen and Emhjellen547 argue in their 2010 paper that CCS does not offer a protable proposition and delivers CO2 abatement at ‘very high cost’. or near.552 The effect of a sub-optimal pipeline network is to make overall costs per unit of output (MWh of electricity or tonne of CO2 stored) higher than they could otherwise be. Depending on the contribution of nuclear and wind power to the generation mix. Abadie and Chamorro544 concluded that in the face of the risks associated with uncertain returns. Downloaded on 05/11/2015 11:56:07. A CCS plant in the current market may therefore be squeezed between low variable cost ‘price takers’ (nuclear and wind) and low capital cost ‘price makers’ (CCGT). coal Post-combustion. but the characteristics of CCS described above still present a signicant challenge. coal Pre-combustion. Of course. coal Oxyfuel. Evar assessed stakeholder perceptions of the uncertainties over CCS technology development and whether support levels will be sufficient: he concluded that ‘experts express certitude in the prospects for deploying largescale CCS technology in the UK. 130–189 Romania UK also concluded from a real-options based assessment that the CO2 price required to overcome these risks and incentivise CCS investment was more than four times that which is suggested by a typical Net Present Value (NPV) assessment.GEN North Killingholme Power Station Zero Emission Porto Tolle ULCOS-BF Pre-combustion. 7.. gas Pre-combustion.550. gas costs. a proportion of any CCS eet may be able to run at. there appears to be something of a consensus emerging that the policy support mechanisms under consideration. investment in CCS on coal plants will be delayed. is still not low-carbon. coal UK Poland Netherlands UK UK Captain Clean Energy Project Peterhead Gas CCS Project The Teeside CCS Project White Rose Project Pre-combustion. biomass Post-combustion. EC NER 300 CCS projects (ranked order) UK CCS projects (alphabetical order) Project Type. and still more than three times even if the additional capital cost is covered by full subsidy. and coal plants whose build costs were sunk several decades ago.551 Further issues which concern analysts are pipeline network sizing and the potential long-term liability that CO2 storage represents. thus undermining the attractiveness of CCS investments unless investors can be sure of receiving high prices when plants do run. policy design does need to recognise the specic techno-economic characteristics of CCS and the need for substantial capital grants for early projects. there is coverage of: storage site selection (Article 4). 17. However. The Global CCS Institute have called for ‘substantial. That a storage site must feature effective monitoring and reporting requirements to the regulatory authority. or can be compensated in some other way. for example through the proposed capacity payment mechanism. Downloaded on 05/11/2015 11:56:07. the unique characteristics of CCS present both signicant opportunities and policy challenges. Although fossil fuel plants are typically ‘price makers’. wind and solar photovoltaics also generally require support. and the lack of a systematic policy approach to coordinating and optimising the network through. CCS plant might be required to operate exibly (and therefore at lower load factors) when there is increased penetration of very-low-marginal-cost nuclear and wind power plants.526 reinforcing the IEA’s call for a ‘stable but exible’ policy framework. and ensure that the CO2 transportation networks are built up in the most efficient longterm manner. The multiplicity of CCS technologies. which may mean that load factor risk could become important by the late 2020s. closure and post-closure obligations (Chapter 4). This risk is potentially greater for coal CCS than gas CCS. Combining these attributes with the potential for geographically diversied fuels sources explains why CCS technologies feature so strongly in many countries’ CO2 emissions reduction strategies. In particular. each of which has differing technological characteristics.1 The CCS directive The Directive559 provides the legislative basis for safe geological storage of carbon dioxide. due to the higher capital intensity of coal plant. There are also more general uncertainties about the legal liabilities of CO2 storage. This has the potential to increase the unit costs (£/MWh) of CCS generation.. In particular.View Article Online Review liability is a commercially insurable risk. What is revealed in particular is the need for greater regulatory certainty and legal and nancial assurances for would be CCS investors and operators of CCS storage sites. makes this factor especially difficult to tackle. together with delays in the UK demonstration programme. etc. 7. The high up-front capital costs of CCS projects (and the uncertainty around those costs). the CCS Directive provides a signicant number of risk management opportunities for UK regulators while placing signicant costs on storage operators. among the regulatory risk management opportunities available to governments are the rights of authorities to require the following: That no storage site which may leak or create undue environmental or health risks shall be permitted. to seek strict permit conditions such that human error will be reduced in respect of technical compliance. That a storage site shall not operate without a permit and observance of all permit conditions.555 Published on 13 September 2013. Research undertaken by the UK Energy Research Centre556–558 suggests that signicant concerns remain and these can summarised as follows: Technology and construction risk is a particularly important factor deterring investment at present. 17. storage permits (Article 6). timely and stable’ policy support. exible. Finally. there are concerns that the FiT CfD support mechanism for UK projects may remove this natural hedge unless the mechanism is also linked to fuel prices. Energy Environ. the EU directive on CO2 storage. Whilst other low carbon power generation technologies such as nuclear. 2014. not to approve storage sites with risky geological proles. That the regulator must be notied immediately of leakages or irregularities at the site. There are comprehensive requirements for storage addressing the life cycle of prospective storage sites. Sci. The infrastructural barriers to CCS investment include the rst-of-a-kind costs associated with developing a CO2 transportation network. for example. address the inherent fuel price risk. which seems likely to mandate a long term liability fund.2 Continuing challenges facing CCS policy support mechanisms The UK and EU clearly do have substantial policy support offerings for CCS but the key question is whether they will be sufficient to deliver both the early-stage investment in demonstration plants and the large-scale CCS deployment that will be required if the technology is to make a meaningful contribution to meeting climate policy goals. low carbon generation—which will have particular value in electricity systems with large contributions from technically or This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science economically inexible generation such as wind and nuclear power. For example. permits for exploration (Article 5). It makes passing references to capture and transport activities. which creates a fuel price risk. CCS has signicant and variable fuel-related operating costs. with the ability to pass fuel price increases on to consumers. CCS has relatively high operating and fuel costs. are exacerbating this risk. 130–189 | 171 . pipeline oversizing. In summary. UK and EU legislative responses to CCS This section explores the main features of the EU and UK legislative frameworks for CCS.525 What is also clear is that time is of the essence if CCS technologies are to be developed and deployed at the scale implied by global policy aspirations. 16. there are rules prescribed for transfer of site-based responsibilities (Article 18). Additionally.554 On the other hand. and the EMR’s emphasis on premium payments for electricity generated rather than up-front capital grants. and operation. This analysis is cast against a not inconsiderable concern over the nancial and regulatory risk management dimensions of the technology. may go some to way to addressing these concerns. That no storage site shall be permitted without requisite levels of nancial security and technical excellence. The opportunities include the potential for dispatchable. Financial security measures are also to be undertaken by storage site operators further to Article 14 of the Environmental Liability Directive. including those due to leakage(s). The Emissions Trading Directive561 If we move on to the Emissions Trading Directive. it has previously been demonstrated that regulators do not accept such a transfer of responsibility in analogous environmental law elds (in Canada and the United States) pertaining to waste management facilities and contaminated land sites. There is no cap on the EUA price. As this is the second key decision in the lifecycle of a storage site (the rst being the decision to permit the site for use). Hence. This calculation will require (i) estimates for the total tons of emissions that may be released. (ii) the timing of emissions. It also allows for the exclusion of liability on behalf of operators. as a compensatory measure for loss of CO2 stored. Downloaded on 05/11/2015 11:56:07. and is not. Article 18) that potential storage site operator liabilities and nancial obligations end within approximately 20 years (given as a minimum period).3. As such the CCS Directive spells out framework requirements to ensure the long-term stewardship of storage sites.1-2 language is such that the conditions 1(a) “complete and permanent storage” may not be proven by that time. and (iii) costs of allowances when releases occur. through requests for more monitoring data for example. a storage site shall be transferred (legal liabilities included) to the state when: All available evidence indicates that the CO2 will be completely contained for the indenite future. and 2(c) site evolution “towards a situation of long-term stability” may not be proven by that time. Energy & Environmental Science That a storage site will be closed for breach of permit conditions. This journal is © The Royal Society of Chemistry 2014 . However. as calculated pursuant to the Monitoring and Reporting Guidelines for CCS. where they are not at fault or are otherwise not negligent. Arguably. a cap on EUA prices. 17. the Environmental Liability Directive brings storage site operations within the liability framework of the European Union. Further to Article 34 of the CCS Directive. Furthermore. In respect of commercial scale storage sites. Sci. The amount of the Financial Security (FS) for this obligation can be based on the potential total tons of emissions. As such.2 The Environmental Liability Directive560 The CCS Directive itself does not address the specic mechanics of liability. A minimum period before transfer to be determined by the competent authority has elapsed. In such circumstances. 7. In terms of nancial risk derived from liability. The need to hedge against such risk becomes important when it is likely that liability for allowances would entail greater costs over time as carbon prices rise. would be with a signicantly higher price tag than those bought today. that can only occur once the Competent Authority has been assured that no leakage is likely to occur. this loose Directive language offers regulators an open door to deny the transfer of responsibility from the storage site operator to the competent authority at the 20 year threshold. it is worth noting that the purchase of emissions credits serves as a climate change mitigation and prevention strategy in itself. by virtue of the inclusion of geological storage sites under Annex I of the Emissions Trading Directive. There is a perception (CCS Directive. the penalty for excess emission (100 V t1) does not relieve the operator of the need to provide allowances to cover the emissions. including those due to leakage(s). 130–189 Review This issue ought to be considered by rms operating in particularly risk adverse government jurisdictions. the assumption of long-term emissions credits liability would mean that allowances which are bought in the future. which would further defer investments. however. including leakage. a Commission review is foreseen at this stage too. This applies to all relevant “environmental damage” and corresponding duties of prevention (Article 5) and remediation/ mitigation (Article 6) under the Environmental Liability Directive. operators of CCS sites have obligations in respect of the prevention and remediation of environmental damage associated with such sites. multiplied by the market cost of purchasing an equivalent amount of allowances. there is unavoidable uncertainty about the future price of EU Allowances (EUA) at the time of any potential leakage. Transfers can be innitely stalled by competent authorities. (The operator retains responsibility for a site whilst it presents a signicant risk of leakage. a liability of this kind is not insurable and presents an incalculable risk to potential storage site operators. That there shall be proportionate penalties for regulatory infractions. As such. That the storage site operator will comply with strict closure and aercare requirements. it is worth recalling that geological storage will extend over long periods of time. The sheer weight and nature of risk management opportunities available to the regulator and the commensurate risk management standards. (b) the 20 year period is a minimum. Guidance Document 4 observations aside. A exible interpretation of Article 14 allows for the use of ceilings on nancial instruments. That all environmental and related nancial liabilities may be placed on the storage site operator. 172 | Energy Environ. we must look to the Environmental Liability Directive and the Emissions Trading Scheme Directive given that the CCS Directive delegates this matter to them. The site has been sealed and the injection facilities have been removed.. The Directive thus provides for sites to be transferred to Member State control in the long term. As such.) Under the CCS Directive. That emission allowances be purchased to cover leakage events. 17. procedures and nancial and related liability requirements placed upon the storage site operators suggests that a “cooperation” or “partnership” approach between industry and regulators to risk management and related long-term and nancial liability for leakage is necessary. installations will be required to surrender allowances for any emissions from the site. therefore. 2014. the nature of Directive Article 18.View Article Online Published on 13 September 2013. A nancial contribution for the post-transfer period covering at least the costs for monitoring for 30 years has been made and. a lease and presumably a rental payment will be required from the Crown Estate. including dra regulations to implement that regime was done in September 2009. consultation on the proposed offshore CO2 licensing regime. The Energy Act introduces a regulatory framework for the licensing of the offshore storage aspect of CCS. 17. This journal is © The Royal Society of Chemistry 2014 Energy & Environmental Science 17. Furthermore. the oil and gas installation decommissioning regime found in the Petroleum Act (1998) will be applied to facilities used for CO2 storage. the UK) including storage space under the sea bed. Energy Environ. Creative legislative solutions in addition to the provision of nance will need to operate in tandem if rst-mover gains in the emerging CCS industry in the UK are to be won in the CCS eld. enforcement and registration of CCS. There is also a strong argument to suggest that in its essence.5 The UK regulatory response Legislative developments at European level have created a regulatory framework for offshore CCS within the European Community. ensure legislation that underpins the long term delivery of our energy and climate change strategy. Given the additional point that carbon storage may well turn out to be a cost vs. In Budget 2007. in law or in fact. This argumentation is supported by the EC Treaty obligation of competition law not to obstruct the performance. 7. This would constitute a drawn-out and cumbersome process.). if CCS operators are legally required to buy emissions credits and CCS operators also bound to cover liability of the same leakage event. the Act states that there is a right of the Crown to have sole jurisdiction from the UK coast line for up to 200 miles out to sea (the so-called Exclusive Economic Zone—EEZ) in relation to the storing of gas. there is a clear double-payment by the private sector. There is also the observation that the revision of EU state aids regulation and guidance for CCS should have taken place at a time that was commensurate with the creation of the CCS Directive. damage to land. such as deep saline formations. For operators seeking to undertake CCS activities within the newly designated EEZ. The Government may also designate ‘Gas Importation and Storage Zones’ within the EEZ. of the particular tasks assigned to services of general economic interest (i. These types of damage occur as a result of anthropogenic climate change as well. The licensing regime also regulates storage in depleted and partially depleted hydrocarbon elds under the sea bed and in non-hydrocarbon geological features.4 EU state aids/competition law There may be those that point to state aids/competition law restrictions on regulatory solutions for nancial instrument and long-term liability regulation further to the CCS Directive. damage in terms of failed climate change mitigation is already covered in respect of the types of damage listed in the EU Environmental Liability Directive (2004/35/EC) (including. etc. The Act also provides a regulatory regime for CO2 storage for certain relevant existing offshore oil and gas legislation. 130–189 | 173 ..View Article Online Review Published on 13 September 2013. 17. the Government announced a competition to design and build full-scale demonstration of CCS projects and it was launched in November 2007. Re-opening the debate would only lead to further market uncertainty at a time when the CCS Directive is just now being enforced. Downloaded on 05/11/2015 11:56:07. whilst amendments to the London Protocol on the Prevention of Marine Pollution by the Dumping of Waste and Other Matter (1972) and the Convention for the Protection of the marine Environment of the North-East Atlantic (OSPAR Convention) to allow for sub-seabed geological storage. The Energy Act 2008 established the enabling provisions for regulating offshore CO2 storage in the UK in November 2008. Furthermore. damage to water. marine ecosystem damage. It is noted to date that the UK and German Governments have taken a favourable position in this regard by adopting a exible approach to state aids and it would appear that the European Commission is similarly disposed. revenue neutral activity some easing of state aids rules/competition law should apply. Whilst supporting the amendments to the London Protocol and OSPAR Convention in 2007. all natural resources belong to the coastal state (i.e. Sci. Thus far. The Energy Bill was unveiled in 2008 which detailed a framework for the licensing. fundamental changes in land use. but not limited to species loss. it is not suggested that a formal procedure be commenced to review the EU General Block Exemption Regulation or Guidelines for State Aid for Environmental Protection562 with the aim of codifying new principles and rules in respect of CCS. Enterprise & Regulatory Reform (BERR) expected that the Bill would provide a sound system.6 The Energy Act 2008563 In summary. which would enable private sector investment in CCS projects and along with the Planning and Climate Change Bills.e. Given the history of CCS Directive negotiation. The Department for Business. This problem of double-counting liability has to be addressed by counterbalanced regulatory solutions that push forward CCS technology investment. the Energy Review of 2006 concluded that should it be proved that CCS is cost effective. According to this Act. UK announced a competition for funding a full-scale demonstration project. the provision of carbon storage for climate change prevention and mitigation). 2014. the next stage would need to be commercial demonstration. storage serves to mitigate climate change and to meet binding emissions reduction targets that are placed upon Governments within an EU and international legal context. By storing carbon that would otherwise have been inevitably produced in order to satisfy energy demand. which is why CO2 as a pollutant has already been determined to be remediated under climate change mitigation measures. For this reason. carbon dioxide storage represents a public good or service that fulls a government function of mitigating climate change. leading Member State Governments have taken a sensible approach to state aid regulation and CCS. provide an international regulatory dimension. Thereby. there would be further uncertainty about the result and Member States and non-State interests that are without direct and active interests and projects in the eld of CCS would still be in a position to inuence the outcome in a manner that may not best serve Member States and private sector actors that wish to advance CCS technology. For example. The energy suppliers have been forced by this Act to reduce the price of fuel for vulnerable consumers in order to reduce fuel poverty when the Voluntary Agreement with the energy suppliers ended in 2011. The Energy Act 2010 gives more authority to the Secretary of State to introduce a Market Power Licence Condition for electricity generators that will make it easier for Ofgem to address certain issues arising from the exploitation of market power where there are constraints on the amount of electricity that can be transmitted. Downloaded on 05/11/2015 11:56:07. In doing so.10 Liability implications and developments in the USA The proposed license is very similar to the licences granted to the petroleum production industry. The Plan makes it clear that we need to cut emissions in a way that helps the sustainable development of our economy. protecting consumers and increasing energy security.7. they set out a range of requirements that operators need to full in order to obtain a storage site permit from the Secretary of State. Additionally. The third amendment is in respect to offshore CCS activities.) regulations 2010565 These Regulations introduce a permitting regime for offshore CCS activities under the authority of Energy Act 2008. It has nalised requirements for CCS through the development of permitting for a new class of storage wells (Class VI) to be used specically for geological storage of CO2.8 The storage of carbon dioxide (licensing etc. it only requires businesses to have one permit instead of several permits for activities falling under the regulations on one site and by doing so. A fundamental part of these schemes is social price support. This means keeping energy supplies safe and secure. it expresses time limited rights to apply for storage permits which would allow site operators to construct storage facilities—including offshore facilities—in order to store the liqueed CO2. The rst two amendments arise from the need to transpose certain parts and provisions of the CCS directive. 17. Four amendments were made to the EP Regulations 2010 and took effect in 2011. 7. as well as obligations between the closure of an installation and the termination of a licence. For example. 17. 17. Moreover. This Plan will deliver emission cuts of 18% on 2008 levels by 2020 (and over a one third reduction on 1990 levels) on the way to achieving a reduction of at least 80% by 2050. According to the Act. decommissioning the site aer use and the monitoring of the stored material’s behaviour during and aer the completion of storage operations. The Energy Act 2008 forms a nancial incentive to support four CCS demonstration projects on power stations which are being powered by coal through a levy mechanism on electricity suppliers. The EPA has proposed a default 50-year time-frame for CCS liability with the provision that the acting EPA Director may shorten or lengthen that period based on risk data gathered during the permitting process.3 Regulation of gas and electricity markets.7. Interestingly. which comes in the form of an electricity bill refund to certain groups of people that are more vulnerable in comparison with others. The licence may include provisions relating to nancial security in respect of future obligations. the US Environmental Protection Agency has adopted a more exible regulatory approach. 17. it has rationalised various permitting regimes into a common framework that is easier to understand and use. 130–189 Review let their consumers know about any potential changes to their contract in terms of pricing or any other changes as such within a certain period of time. post-closure period. the Secretary of State has the power to modify supply licences so that it can be made certain that suppliers will 174 | Energy Environ. and nancial security. maximising economic opportunities and protecting the most vulnerable consumers.1 Carbon capture and storage and decarbonisation. and the nal amendment is regarding the gas produced by anaerobic digestion plants. according to the Act. the licence provides the necessary framework to demonstrate the legal obligations that site operators have with respect to ensuring the safe/secure containment of CO2 under geological formations. This part of the Act claries the responsibilities of Ofgem with respect to climate change.. this new permitting system will allow for nancial guarantees for CCS to be chosen from a variety of different options This journal is © The Royal Society of Chemistry 2014 . society and environment. The 1998 Act also prescribes detailed plans and approvals that require persons seeking to abandon an installation offshore to provide an ‘abandonment programme’ which sets out the ‘measures proposed to be taken in connection with the abandonment of an offshore installation or submarine pipeline’. For instance. obligations of the storage operator.9 Environmental Permitting (EP)566 The EP Regulations 2010 comprise a common set of denitions.View Article Online Published on 13 September 2013. The Act also introduces a detailed section about the enforcement of licences and criminal offences and sanctions when activities are undertaken without a licence or where a licence holder fails to abide by its prescribed conditions. 17. Furthermore. closure of the storage site. The licence would—subject to specic consent for drilling of any well—permit the conduction of intrusive exploration. the Government is required to prepare regular reports on the progress that has been made on the decarbonisation of electricity generation in UK and the development and use of CCS. In addition. Sci. Furthermore. processes and controls for the permitting of specied activities to prevent pollution. 2014. 17. the Secretary of State or the Scottish Ministers grant a licence that may also attach a set of particular requirements for a specic applicant.7. it allows the regulators to focus recourses on higher risk activities. 17. Energy & Environmental Science A regime based upon licensing is introduced and requires a licence from the relevant authority for activities relating to the storage of CO2 (with a view to its permanent disposal).7 Energy Act 2010564 This legislation implements elements of: The UK Low Carbon Transition Plan – a national strategy for climate and energy.2 Schemes for reducing fuel poverty. The Regulations cover the conditions for granting licences and exploration permits. Acknowledgements PSF thanks the RCUK Energy Programme and Engineering and Physical Sciences Research Council for support under EP/ K000446 and Matt Boot-Handford for a PhD studentship under EP/I010912/1. Alto. 4168–4186. J. Florin. Res. Chem. Boston and L. 7238–7239. J. Henry. Jackson and A. 20. Llovell. 2012. 2012. Radosz. Mac Dowell. Stenby and G. Llovell. N. Adjiman.. C. 135–150. 2012. J. B.. 1973. A. 2010. Performance and risks of advanced pulverised coal plant. 18 N. Brussels. Chem. Ind. P. Mac Dowell. Mol. J. 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