Ash and deposit formation from oxy-coal combustion in a 100 kW test furnace

Ash deposition is still an unresolved problem when retrofitting existing air-fired coal power plants to oxy-fuel combustion. Experimental data are quite necessary for mechanism validation and model development. This work was designed to obtain laboratory combustor data on ash and deposits from oxy-coal combustion, and to explore the effects of oxy-firing on their formation. Two bituminous coals (Utah coal and Illinois coal) and one sub-bituminous coal (PRB coal) were burned on a down-fired combustor under both oxy- and air-firing. Two oxy-fired cases, i.e., 27 vol% O₂/73 vol% CO₂ and 32 vol% O₂/68 vol% CO₂, were selected to match the radiation flux and the adiabatic flame temperature of air combustion, respectively. Once-through CO₂ was used to simulate fully cleaned recycled flue gas. The flue gas excess oxygen was fixed at 3 vol%. For each case, both size-segregated fly ash and bulk fly ash samples were obtained. Simultaneously, ash deposits were collected on an especially designed un-cooled deposition probe. Ash particle size distributions and chemical composition of all samples were characterized. Data showed that oxy-firing had insignificant impacts on the tri-modal ash particle size distributions and composition size distributions in the size range studied. Bulk ash compositions also showed no significant differences between oxy- and air-firing, except for slightly higher sulfur contents in some oxy-fired ashes. The oxy-fired deposits were thicker than those from air-firing, suggesting enhanced ash deposition rates in oxy-firing. Oxy-firing also had apparent impacts on the deposit composition, especially for those components (e.g., CaO, Fe₂O₃, SO₃, etc.) that could contribute significantly to ash deposition. Based on these results, aerodynamic changes in gas flow and changes in combustion temperature seemed more important than chemical changes of ash particles in determining deposit behavior during oxy-coal combustion.     

Flue gas desulphurization for hot recycle Oxyfuel combustion: Experiences from the 30 MWth Oxyfuel pilot plant in Schwarze Pumpe

Significant differences exist in the flue gas composition in hot recycle Oxyfuel conditions as e.g. the high CO₂ partial pressure (>90 vol%, dry), the very high SO₂ concentration and the high water content (approx. 30 vol%). Therefore certain design and operation criteria have to be observed for the flue gas desulphurization with forced oxidation under Oxyfuel combustion conditions. Several performance tests have been executed at the 30 MW_th Oxyfuel pilot plant in Schwarze Pumpe to evaluate the main performance parameters and to assess the influence of the major operation parameters. The results show that there are no fundamental problems for the operation of the flue gas desulphurization unit under Oxyfuel combustion conditions. High removal rates could be reached and no negative impact of the high CO₂ partial pressure was observed under the tested operating conditions. No major differences in the gypsum quality have been observed between air firing and Oxyfuel conditions.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Conceptual design of a three fluidised beds combustion system capturing CO2 with CaO

In this work, the Aspen Hysys conceptual design of a new process for energy generation at large scale with implicit CO₂ capture is presented. This process makes use of the CaO capability for CO₂ capture at high temperature and the possibility of regenerating this sorbent working in interconnected fluidised bed reactors operating at different temperatures. The proposed process has the advantage of producing power with minimum CO₂ emissions and very low energy penalties compared with similar air-based combustion power plants. In this system, five main parts can be distinguished: the combustor where coal is burnt with air, the calciner where the fresh and the recycled CaCO₃ is calcined, the carbonator where the CO₂ produced in the combustor is captured, the supercritical steam cycle and the CO₂ compression system. In this arrangement, the three fluidised bed reactors are interconnected in such a way that it is possible to perform the CaCO₃ calcination at a temperature of 950 °C with the energy transported by a hot solid stream produced in the circulating fluidised bed combustor operating at 1030 °C. The stream rich in CaO produced in the calciner is split into three parts. One of them is transported to the carbonator operating at 650 °C where most of the CO₂ in the flue gas produced in the combustor is captured. The second one is sent to the combustor, where it is heated up and used as energy carrier. The third solid stream that leaves the calciner is a purge in order to maintain the capture system activity and to avoid inert material accumulation. Because of the high temperatures involved in all the system, it is possible to recover most of the energy in the fuel and to produce power in a supercritical steam cycle. A case study is presented and it is demonstrated that under these operating conditions, 90% CO₂ capture efficiency can be achieved with no energy penalty further than the one originated in the CO₂ compression system.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

The challenge in understanding the corrosion mechanisms under oxyfuel combustion conditions

Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO₂ content and temperatures higher than 500 °C. In SO₂ containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO₂, O₂, and SO₂ contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO₂ separation and treatment process. This work includes major conditions of the flue gas and CO₂ stream in CCS plants and CCS technology.     

Experimental validation of in situ CO2 capture with CaO during the low temperature combustion of biomass in a fluidized bed reactor

A novel concept for capturing CO₂ from biomass combustion using CaO as an active solid sorbent of CO₂ is discussed and experimentally tested. According to the CaO/CaCO₃ equilibrium, if a fuel could be burned at a sufficiently low temperature (below 700 °C) it would be possible to capture CO₂ “in situ” with the CaO particles at atmospheric pressure. A subsequent step involving the regeneration of CaCO₃ in a calciner operating at typical conditions of oxyfired-circulating fluidized combustion would deliver the CO₂ ready for purification, compression and permanent geological storage. Several series of experiments to prove this concept have been conducted in a 30 kW interconnected fluidized bed test facility at INCAR-CSIC, made up of two interconnected circulating fluidized bed reactors, one acting as biomass combustor-carbonator and the other as air-fired calciner (which is considered to yield similar sorbent properties than those of an oxyfired calciner). CO₂ capture efficiencies in dynamic tests in the combustor-carbonator reactor were measured over a wide range of operating conditions, including different superficial gas velocities, solids circulation rates, excess air above stoichiometric, and biomass type (olive pits, saw dust and pellets). Biomass combustion in air is effective at temperatures even below the 700 °C, necessary for the effective capture of CO₂ by carbonation of CaO. Overall CO₂ capture efficiencies in the combustor-carbonator higher than 70% can be achieved with sufficiently high solids circulation rates of CaO and solids inventories. The application of a simple reactor model for the combined combustion and CO₂ capture reactions allows an efficiency factor to be obtained from the dynamic experimental test that could be valuable for scaling up purposes.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Study of Hg and SO3 behavior in flue gas of oxy-fuel combustion system

Oxy-fuel combustion systems have been under development to reduce CO₂ emissions from coal-fired power plants. In oxy-fuel combustion system, Hg in the flue gas causes corrosion in CO₂ purification and compression units. Also, SO₃ in the flue gas corrodes the equipment and ducts of oxy-fuel combustion system. Therefore, Hg and SO₃ need to be removed.Babcock-Hitachi conducted tests using a 1.5 MWth Combustion & Air Quality Control System (AQCS) test facility which consists of oxygen supply unit, furnace, Selective Catalytic Reduction (SCR) catalyst, Clean Energy Recuperator (CER), Dry Electrostatic Precipitator (DESP), flue gas recirculation system, Wet Flue Gas Desulfurization (WFGD), and CO₂ Compression and Purification Unit (CPU). In both cases of air and oxy-fuel combustion, the Hg removal across the DESP could be improved, and SO₃ concentration at the DESP outlet could be reduced to less than 1 ppm by installing a CER upstream of the DESP and reducing the gas temperature at the DESP inlet. Hg was not dissolved in the drain recovered from CO₂ compressor, and may be adsorbed at an inner part of CO₂ compressor. This indicated that Hg needs to be removed at a location upstream of the CO₂ compressor to prevent corrosion of the compressor.     

CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Effect of gas composition in Chemical-Looping Combustion with copper-based oxygen carriers: Fate of sulphur

Chemical-Looping Combustion (CLC) is an emerging technology for CO₂ capture because separation of this gas from the other flue gas components is inherent to the process and thus no energy is expended for the separation. Natural or refinery gas can be used as gaseous fuels and they may contain different amounts of sulphur compounds, such as H₂S and COS. This paper presents the combustion results obtained with a Cu-based oxygen carrier using mixtures of CH₄ and H₂S as fuel. The influence of H₂S concentration on the gas product distribution and combustion efficiency, sulphur splitting between the fuel reactor (FR) and the air reactor (AR), oxygen carrier deactivation and material agglomeration was investigated in a continuous CLC plant (500 W_th). The oxygen carrier to fuel ratio, ?, was the main operating parameter affecting the CLC system. Complete fuel combustion were reached at 1073 K working at ? values ≥1.5. The presence of H₂S did not produce a decrease in the combustion efficiency even when working with a fuel containing 1300 vppm H₂S. At these conditions, the great majority of the sulphur fed into the system was released in the gas outlet of the FR as SO₂, affecting to the quality of the CO₂ produced. Formation of copper sulphide, Cu₂S, and the subsequent reactivity loss was only detected working at low values of ? ≤ 1.5, although this fact did not produce any agglomeration problem in the fluidized beds. In addition, the oxygen carrier was fully regenerated in a H₂S-free environment. It can be concluded that Cu-based oxygen carriers are adequate materials to be used in a CLC process using fuels containing H₂S although quality of the CO₂ produced is affected.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Multi-stage chemical looping combustion (CLC) for combined cycles with CO2 capture

This paper presents application of the chemical looping combustion (CLC) method in natural gas-fired combined cycles for power generation with CO₂ capture. A CLC combined cycle consisting of single CLC-reactor system, an air turbine, a CO₂-turbine and a steam cycle has been designated as the base-case cycle. The base-case cycle can achieve net plant efficiency of about 52% at an oxidation temperature of 1200 °C. In order to achieve a reasonable efficiency at lower oxidation temperatures, reheat is introduced into the air turbine by employing multi CLC-reactors. The results show that the single reheat CLC-combined cycle can achieve net plant efficiency of above 51% at oxidation temperature of 1000 °C and above 53% at the oxidation temperature of 1200 °C including CO₂ compression to 110 bar. The double reheat cycle results in marginal efficiency improvement as compared to the single reheat cycle. The CLC-cycles are also compared with a conventional combined cycle with and without post-combustion capture in amine solution. All the CLC-cycles show higher net plant efficiencies with close to 100% CO₂ capture as compared to a conventional combined cycle with post-combustion capture, which is very promising.     

Oxy-fuel coal combustion—A review of the current state-of-the-art

Carbon dioxide emissions will continue being a major environmental concern due to the fact that coal will remain a major fossil-fuel energy resource for the next few decades. To meet future targets for the reduction of greenhouse gas (GHG) emissions, capture and storage of CO₂ is required. Carbon capture and storage technologies that are currently the focus of research centres and industry include: pre-combustion capture, post-combustion capture, and oxy-fuel combustion. This review deals with the oxy-fuel coal combustion process, primarily focusing on pulverised coal (PC) combustion, and its related research and development topics. In addition, research results related to oxy-fuel combustion in a circulating fluidised bed (CFB) will be briefly dealt with.During oxy-fuel combustion, a combination of oxygen, with a purity of more than 95 vol.%, and recycled flue gas (RFG) referred to as oxidant is used for combusting the fuel producing a gas consisting of mainly CO₂ and water vapour, which after purification and compression, is ready for storage. The high oxygen demand is supplied by a cryogenic air separation process, which is the only commercially available mature technology. The separation of oxygen from air as well as the purification and liquefaction of the CO₂-enriched flue gas consumes significant auxiliary power. Therefore, the overall net efficiency is expected to be decreased by 8–12% points, corresponding to a 21–35% increase in fuel consumption. Alternatively, ion transport membranes (ITMs) are proposed for oxygen separation, which might be more energy efficient. However, since ITMs are far away from becoming a mature technology, it is widely expected that cryogenic air separation will be the selected technology in the near future. Oxygen combustion is associated with higher temperatures compared with conventional air combustion. Both fuel properties as well as limitations of steam and metal temperatures of the various heat exchanger sections of the boiler require a moderation of the temperatures in the combustion zone and in the heat-transfer sections. This moderation in temperature is accomplished by means of recycled flue gas. The interdependencies between the fuel properties, the amount and temperature of the recycled flue gas, and the resulting oxygen concentration in the combustion atmosphere are reviewed.The different gas atmosphere resulting from oxy-fuel combustion gives rise to various questions related to firing, in particular, with respect to the combustion mechanism, pollutant reduction, the risk of corrosion, and the properties of the fly ash or its resulting deposits. In this review, detailed nitrogen and sulphur chemistry was investigated in a laboratory-scale facility under oxy-fuel combustion conditions. Oxidant staging succeeded in reducing NO formation with effectiveness comparable to that typically observed in conventional air combustion. With regard to sulphur, a considerable increase in the SO₂ concentration was measured, as expected. However, the H₂S concentration in the combustion atmosphere in the near-flame zone increased as well. Further results were obtained in a pilot-scale test facility, whereby acid dew points were measured and deposition probes were exposed to the combustion environment. Slagging, fouling and corrosion issues have so far been addressed via short-term exposure and require further investigation.Modelling of PC combustion processes by computational fluid dynamics (CFD) has become state-of-the-art for conventional air combustion. Nevertheless, the application of these models for oxy-fuel combustion conditions needs adaptation since the combustion chemistry and radiative heat transfer is altered due to the different combustion gas atmosphere.CFB technology can be considered mature for conventional air combustion. In addition to its inherent advantages like good environmental performance and fuel flexibility, it offers the possibility of additional heat exchanger arrangements in the solid recirculation system, i.e. the ability to control combustion temperatures despite relatively low flue gas recycle ratios even when combusting in the presence of high oxygen concentrations.     

CO2 removal using membrane gas absorption

The objective of this study is to investigate the potential process for the removal of carbon dioxide (CO₂) from flue gas using fundamental membrane contactor, which is a membrane gas absorption (MGA) system. The experiments consisted of microporous polyvinylidenefluoride (PVDF) flat sheet membrane with 0.1 μm (as module I) and 0.45 μm (as module II) pore size. 2-Amino-2-methyl-1-propanol (AMP) solution was employed as the liquid absorbent. The effect of AMP concentration was studied with variation in the range 1–5 M. In addition, the experiments were carried out with 10%, 20%, 30% and 40% gas ratio of CO₂ to N₂ and pure CO₂ as well. Through contact angle measurement, membranes for module I and module II were obtained with CA values of around 130.25° and 127.77°, respectively. The mass transfer coefficients for module II are lower than those of module I for 1–5 M of AMP. Furthermore, the increase in CO₂ concentration in the feed gas stream enhanced the CO₂ flux as the driving force of the system was increased in sequence from 1 M to 5 M of AMP. However, after the particular percentage (40%) of CO₂ inlet concentration, the CO₂ fluxes seem saturated. The combination of AMP as liquid absorbent and PVDF microporous membrane in MGA system has shown the potential to remove the CO₂ from flue gas. In addition, the higher AMP concentration gave higher mass transfer coefficient at low liquid flow rates.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.     

Parametric investigation of the calcium looping process for CO2 capture in a 10 kWth dual fluidized bed

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

Gas conditioning—The interface between CO2 capture and transport

Gas conditioning is commonly referred to as the required processing for a produced natural gas to achieve transport and sales specifications. In this paper, gas conditioning as the processing required in the interface between CO₂ capture and transport is studied for nine different natural gas fired power plant concepts and three different CO₂ transport processes. Conditioning processes for both pipeline and ship transport are described and an enhanced process for volatile removal is developed. The energy requirement for the conditioning processes is normally between 90 and 120 kWh/tonne CO₂; however, this depends on the pressure and composition of the captured CO₂-rich stream. The loss of CO₂ in the water purge is small for most capture processes. The waste streams from the gas conditioning processes can contain large amounts of CO₂ and should therefore be further processed or reintroduced at an appropriate point upstream in the capture or gas conditioning process if possible. The integration benefit may vary depending on the composition of the CO₂-rich stream. It could be particularly interesting for processes with “innovative reactors” (membranes, sorbents, chemical looping) to integrate CO₂ capture and gas conditioning.     

Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

Chemical-looping combustion using syngas as fuel

Chemical-looping combustion (CLC) is a combustion technology where an oxygen carrier is used to transfer oxygen from the combustion air to the fuel, avoiding direct contact between air and fuel. Thus, CO₂ and H₂O are inherently separated from the rest of the flue gases and the carbon dioxide can be obtained in a pure form without the use of an energy intensive air separation unit. The paper presents results from a 3-year project devoted to developing the CLC technology for use with syngas from coal gasification. The project has focused on: (i) the development of oxygen carrier particles, (ii) establishing a reactor design and feasible operating conditions and (iii) construction and operation of a continuously working hot reactor. Approximately, 300 different oxygen carriers based on oxides of the metals Ni, Fe, Mn and Cu were investigated with respect to parameters, which are important in a CLC system, and from these investigations, several particles were found to possess suitable qualities as oxygen carriers. Several cold-model prototypes of CLC based on interconnected fluidized bed reactors were tested, and from these tests a hot prototype CLC reactor system was constructed and operated successfully using three carriers based on Ni, Fe and Mn developed within the project. The particles were used for 30–70 h with combustion, but were circulated under hot conditions for 60–150 h.