Synthetic Flue Gas Research Articles

A new pilot absorber for CO2 capture from flue gases: Measuring and modelling capture with MEA solution

A pilot absorber column for CO2 recovery from flue gases was constructed and tested with aqueous 30wt% monoethanolamine (MEA), a primary amine, as capture solvent. The pilot plant data were compared with a mathematical rate based packed-column model. The simulation results compared well with the pilot plant data.The packed height of the column can be varied from 1.6 to 8.2m by means of five different liquid inlets. The column has an inner diameter of 100mm and is packed with structured Mellapak 250Y packing. Counter-current flow is used.The pilot plant performance was investigated by changing three parameters: the absorption height, liquid flow rate, and the loading of lean MEA. This was done using a synthetic flue gas consisting of 10% CO2 with a flow rate of approximately 33m3/h at ambient temperature and atmospheric pressure. 23 runs were performed.It was observed that while CO2 recovery increases with an increase in flow rate of absorbent and absorption height, it decreases as the lean CO2-loading of the absorbent increases. In addition it has been possible to obtain temperature bulges in the bottom part of the absorber by the applied operation conditions. Bulges are observed at liquid flows around 4.2L/min and below. The results showed that is was possible to achieve 80% recovery with 3.3m absorption height and a liquid flow of 2.1L/min. The simulations show good agreement with the experimental values, although slight deviations arise as the CO2-loading increases and the temperature bulge becomes more distinct.

Effect of coal petrology and pressure on wetting properties of wet coal for CO2 and flue gas storage

The injection of carbon dioxide (CO2) or flue gas into coal layers enhances the coal bed methane production (ECBM) and offers an option for CO2-storage. The success of this process depends on different factors, among them wetting behavior of the coal plays an important role, which is a function of pressure, temperature, coal rank and composition of the gas.The wettability behavior of wet coal samples (semi-anthracite), with respect to injection of synthetic flue gas and pure CO2, was investigated in a modified pendant drop cell at a constant temperature of 318K and pressures varying between 0.2 and 16MPa. For the semi-anthracite Selar Cornish sample, the wettability alteration from intermediate-wet to gas-wet with CO2 injection was observed at pressures above 5.7MPa. Experimental results with synthetic flue gas revealed that the wettability of Selar Cornish coal is intermediate-wet at all pressures and the contact angle only slightly increases with increasing pressure.Comparison between high rank (semi-anthracite) and medium (high volatile bituminous (hvBb)) coals confirms that hydrophobicity increases with the coal rank for samples with a similar bulk mineral content. The results of the contact angle experiments are input parameters for field scale reservoir modeling.

A High Temperature Lithium Orthosilicate-Based Solid Absorbent for Post Combustion CO2 Capture

Capture of carbon dioxide from combustion processes presents a unique and challenging technical problem arising from low CO2 partial pressures, high flow rates, and the presence of water vapor and reactive contaminants such as SO2. A series of solid sorbents were evaluated to determine suitability for postcombustion capture. A lithium orthosilicate (Li4SiO4)-based absorbent supplied by Toshiba Corporation was found to have the most promising properties. The absorbent reacts chemically with CO2 at elevated temperatures (550 °C) to form lithium carbonate (Li2CO3) and lithium metasilicate (Li2SiO3). The presence of water vapor was shown to greatly enhance CO2 absorption rates without affecting capacity. Breakthrough capacities of ∼5–6 mmol/g (22–26 wt %) were obtained using a “clean” synthetic flue gas containing 15% CO2 and 10% H2O in N2 at 550 °C. Experimental studies showed that the absorbent used in a fixed bed process will likely require a thermal swing process with absorption at 550 °C and regeneration...

Limestone in flue gas desulphurization in oxygen-enriched atmospheres - Part I: The effect of CO2 on limestone calcination

Limestone in flue gas desulphurization in oxygen-enriched atmospheres - Part I: The effect of CO2 on limestone calcination The article describes the testing of four selected samples of limestone originating from four commercially exploited deposits. The tests of sorbents included a physicochemical analysis and calcination in different atmospheres. The main aim of the tests was to determine the possibilities for using limestone during combustion in oxygen-enriched atmospheres. Tests in a synthetic flue gas composition make it possible to assess the possibility of CaCO3 decomposition in atmospheres with an increased CO2 concentration.

Pilot-Scale Study of CO2 Capture by CaO-Based Sorbents in the Presence of Steam and SO2

Calcium looping cycles require an oxy-fired calciner burning coal for sorbent regeneration. Thus, in addition to O2 and CO2, the flue gases will include both steam and SO2, and similarly, carbonation of real flue gases will occur in the presence of steam. However, to date, most research has been done without either of these two gaseous components present. Here, batch combustion experiments were performed in a pilot-scale fluidized-bed reactor to study the effects of steam and SO2 addition on CO2 capture by limestone-based sorbents calcined under oxygen-enriched air and oxy-fuel conditions. The initial fast kinetically controlled CO2 capture stage was dramatically reduced when the sorbent was calcined at realistic temperatures in the presence of SO2. This is attributed to both greater sintering due to higher local calcination temperatures required by high CO2 concentrations and CaSO4 formation. By contrast, steam in the synthetic flue gas during carbonation extended the initial, high-efficiency CO2 capture...

Experimental Study of Carbon Dioxide Capture from Synthetic Industrial Incinerator Flue Gas with a Pilot and Laboratory Measurements

In this study, we evaluate the sustainability of absorption/desorption technology for CO2 capture from a targeted unit specialized in industrial waste incineration. The purpose of our study is to fill in this shortage by using a pilot set-up to investigate chemical interactions between synthetic flue gas and solvents and their impacts on process performance. At the same time, we complete our prospection by laboratory experiments to study the influence of specific degradation products on process performance. In this paper, we choose to focus on gas absorption. First, we provide our feedback on experimental methods for overall mass transfer coefficient (KGaW) measurements for CO2 absorption. Second, absorption of acidic pollutants, leading to heat stable salts formation, was investigated. Therefore, we used laboratory tools to study the influence of these salts on process performance.

Structural, kinetic and performance characterization of hollow fiber carbon membranes

The hollow fiber carbon membranes (HFCMs) were prepared from different deacetylated cellulose acetate precursors by controlled carbonization procedure with CO 2 purge gas, a heating rate of 4 K/min, a final temperature of 550 °C and a final soak time 2 h. The SEM images and TGA analysis indicated that the carbon membranes form a symmetric structure and a high average weight loss during the carbonization process. The Langmuir affinity parameters of the carbon membranes were estimated by the CO 2 and N 2 adsorption equilibrium data. The membrane structure parameters of micropore volume, average pore size and d-spacing were determined by the CO 2 adsorption experiments combined with XRD characterization. The kinetic rate constants were also obtained from the CO 2 kinetic adsorption experiments. Single gas permeation tests of H 2, CO 2, O 2, N 2 and CH 4 were conducted to investigate the transport mechanism in the carbon membrane separation process. Moreover, the influences of temperature and feed pressure on the gas separation performances were also studied on the basis of the single gas and gas mixture (synthetic flue gas, CO 2–N 2–O 2) measurements.

Silver impregnated carbon for adsorption and desorption of elemental mercury vapors

The Hg 0 vapor adsorption experimental results on a novel sorbent obtained by impregnating a commercially available activated carbon (Darco G60 from BDH) with silver nitrate were reported. The study was performed by using a fundamental approach, in an apparatus at laboratory scale in which a synthetic flue gas, formed by Hg 0 vapors in a nitrogen gas stream, at a given temperature and mercury concentration, was flowed through a fixed bed of adsorbent material. Breakthrough curves and adsorption isotherms were obtained for bed temperatures of 90, 120 and 150°C and for Hg 0 concentrations in the gas varying in the range of 0.8–5.0 mg/m 3. The experimental gas-solid equilibrium data were used to evaluate the Langmuir parameters and the heat of adsorption. The experimental results showed that silver impregnated carbon was very effective to capture elemental mercury and the amount of mercury adsorbed by the carbon decreased as the bed temperature increased. In addition, to evaluate the possibility of adsorbent recovery, desorption was also studied. Desorption runs showed that both the adsorbing material and the mercury could be easily recovered, since at the end of desorption the residue on solid was almost negligible. The material balance on mercury and the constitutive equations of the adsorption phenomenon were integrated, leading to the evaluation of only one kinetic parameter which fits well both the experimentally determined breakthrough and desorption curves.

Wettability determination by contact angle measurements: hvbB coal–water system with injection of synthetic flue gas and CO 2

Geological sequestration of pure carbon dioxide (CO 2) in coal is one of the methods to sequester CO 2. In addition, injection of CO 2 or flue gas into coal enhances coal bed methane production (ECBM). The success of this combined process depends strongly on the wetting behavior of the coal, which is function of coal rank, ash content, heterogeneity of the coal surface, pressure, temperature and composition of the gas. The wetting behavior can be evaluated from the contact angle of a gas bubble, CO 2 or flue gas, on a coal surface. In this study, contact angles of a synthetic flue gas, i.e. a 80/20 (mol%) N 2/CO 2 mixture, and pure CO 2 on a Warndt Luisenthal (WL) coal have been determined using a modified pendant drop cell in a pressure range from atmospheric to 16 MPa and a constant temperature of 318 K. It was found that the contact angles of flue gas on WL coal were generally smaller than those of CO 2. The contact angle of CO 2 changes from water-wet to gas-wet by increasing pressure above 8.5 MPa while the one for the flue gas changes from water-wet to intermediate-wet by increasing pressure above 10 MPa.

Comparative study on differently concentrated aqueous solutions of MEA and TETA for CO2 capture from flue gases

Next to IGCC and oxyfuel technology amine scrubbing is one possible process pursued for industrial-scale CO2 capture from power plant flue gases. Aqueous solutions of Monoethanolamine (MEA) are commonly used for the existing amine scrubbing processes because of their high reaction kinetics during CO2 absorption. However, the required energy demand for regeneration of the MEA solution is comparably high, requiring improvements in process technology and solvent development. Within this work the results from lab-scale experimental research on the CO2 absorption from flue gases using differently concentrated aqueous solutions of MEA and Triethylenetetramine (TETA) are presented and discussed. The amine content of the solutions was varied in order to show the influence of concentration on CO2 loading, cyclic capacity and limitations within physical parameters. The equilibrium CO2 loading of the concentrated amine solutions was obtained at temperatures from 30 to 95°C using synthetic flue gas with different CO2 concentrations of up to 15vol% CO2. From these results the cyclic capacities of the different solutions are calculated and discussed with focus on the influence of the amine concentration. Furthermore MEA and TETA will be compared on molar and mass basis specifying the significance of TETA as polyamine and its advantages regarding the scrubbing process.

Influence of the Concentration of CO2 and SO2 on the Absorption of CO2 by a Lithium Orthosilicate-Based Absorbent

A novel, high temperature solid absorbent based on lithium orthosilicate (Li(4)SiO(4)) has shown promise for postcombustion CO(2) capture. Previous studies utilizing a clean, synthetic flue gas have shown that the absorbent has a high CO(2) capacity, >25 wt %, along with high absorption rates, lower heat of absorption and lower regeneration temperature than other solids such as calcium oxide. The current effort was aimed at evaluating the Li(4)SiO(4) based absorbent in the presence of contaminants found in typical flue gas, specifically SO(2), by cyclic exposure to gas mixtures containing CO(2), H(2)O (up to 25 vol. %), and SO(2) (up to 0.95 vol. %). In the absence of SO(2), a stable CO(2) capacity of ∼ 25 wt % over 25 cycles at 550 °C was achieved. The presence of SO(2), even at concentrations as low as 0.002 vol. %, resulted in an irreversible reaction with the absorbent and a decrease in CO(2) capacity. Analysis of SO(2)-exposed samples revealed that the absorbent reacted chemically and irreversibly with SO(2) at 550 °C forming Li(2)SO(4). Thus, industrial application would require desulfurization of flue gas prior to contacting the absorbent. Reactivity with SO(2) is not unique to the lithium orthosilicate material, so similar steps would be required for other absorbents that chemically react with SO(2).

Sour compression process for the removal of SO and NO from oxyfuel-derived CO2

Abstract Coal-fired power stations under oxyfuel combustion produce a raw CO2 product which contains impurities such as water, oxygen, nitrogen and argon from excess oxygen and air leakages. There are also acid gases present, such as SO3, SO2, HCl and NOX produced as by-products of combustion. These acidic impurities will need to be removed from the CO2 stream before it is introduced into the pipeline to prevent corrosion and comply with possible regulations. There may also be stringent requirements on purity, particularly for applications such as enhanced oil recovery. A novel compression method of producing NOx-free, SO2free CO2 was proposed in GHGT-8 [1] , [2] , [3] , [4] , [5] , [6] where SO2 and NOx are removed as H2SO4 and HNO3respectively by compression and water contact of the flue gas. At GHGT-9, initial experimental results were presented using actual fluegas via a sidestream from Doosan Babcock’s 160 kW coal-fired oxyfuel rig, showing the feasibility of the process eliminating 99% SOx and 90% NOx compounds. In this paper, we report on the effects of pressure, temperature, residence time and presence of water in a laboratory scale apparatus using synthetic flue gas.

Enhancement of Indirect Sulphation of Limestone by Steam Addition

The effect of water (H₂O(g)) on in situ SO₂ capture using limestone injection under (FBC) conditions was studied using a thermobalance and tube furnace. The indirect sulphation reaction was found to be greatly enhanced in the presence of H₂O(g). Stoichiometric conversion of samples occurred when sulphated with a synthetic flue gas containing 15% H₂O(g) in under 10 h, which is equivalent to a 45% increase in conversion as compared to sulphation without H₂O(g). Using gas pycnometry and nitrogen adsorption methods, it was shown that limestone samples sulphated in the presence of H₂O(g) undergo increased particle densification without any significant changes to pore area or volume. The microstructural changes and observed increase in conversion were attributed to enhanced solid-state diffusion in CaO/CaSO₄ in the presence of H₂O(g). Given steam has been shown to have such a strong influence on sulphation, whereas it had been previously regarded as inert, may prompt a revisiting of the classically accepted sulphation models and phenomena. These findings also suggest that steam injection may be used to enhance sulfur capture performance in fluidized beds firing low-moisture fuels such as petroleum coke.

Low‐Temperature De‐NOx by Selective Catalytic Reduction Based on Iron‐Based Catalysts

AbstractLow‐temperature De‐NOx technology is a new topic in the area of flue gas treatment. This paper presents experimental studies on selective catalytic reduction (SCR) of NOx from synthetic flue gas over iron‐based catalysts with ammonia in a fluidized reactor. The iron‐based catalysts used in the experiments are particles of Fe3O4 and γ‐Fe2O3, and they are analyzed by X‐ray diffraction (XRD) and Mössbauer spectroscopy, before and after reaction. It is observed that the efficiency of De‐NOx with γ‐Fe2O3 catalyst is high at temperatures from 200–290 °C and the maximum efficiency is seen to exceed 90 % at 250 °C. The effects of magnetic fields on SCR De‐NOx using γ‐Fe2O3 particles as catalysts are also studied by applying uniform and coaxial magnetic fields to the fluidized bed. The results suggest that SCR De‐NOx on γ‐Fe2O3 catalyst is fit for operation below 200 °C in the fluidized reactor in conjunction with the effects of magnetic fields.

The effect of water on the sulphation of limestone

A series of tests was conducted in a thermogravimetric analyzer (TGA) to study the sulphation behaviour of limestone in the presence of water over the temperature range of 800–850 °C. Four different Canadian limestones, all with a particle size range of 75–425 μm, were sulphated using a synthetic flue gas with a composition of 15% CO 2, 3% O 2, 0% or 10% H 2O, 1750 ppm SO 2 and the balance N 2. Water was shown to have a significant promotional effect on sulphation, especially in the diffusion-controlled stage. However, the effect of water during the kinetic-controlled stage appeared to be much less pronounced. Based on these results, it is proposed that the presence of water leads to the transient formation of Ca(OH) 2 as an intermediate, which in turn reacts with SO 2 at a faster rate than CaO does. Alternatively stated, it appears that H 2O acts as catalyst for the sulphation reaction of CaO.

Competition of Sulphation and Carbonation Reactions during Looping Cycles for CO2 Capture by CaO-Based Sorbents

Two types of sorbents are investigated here (natural limestone and highly reactive calcium aluminate pellets) to elucidate their reactivity in terms of sulphation and carbonation and determine the resulting effect on looping cycles for CO(2) capture. The sorbents are tested in a thermogravimetric analyzer (TGA) apparatus using typical synthetic flue gas mixtures containing 15% CO(2) and various concentrations of SO(2). The sulphation and carbonation conversions were determined during sulphation/carbonation/calcination cycles. The sorbent morphology and its changes were determined by means of a scanning electron microscope (SEM). The results showed that sulphation, that is, the formation of CaSO(4) at the sorbent surface, is a cumulative process with increasing numbers of reaction cycles, which hinders sorbent ability to capture CO(2). In the case of high sorbent reactivity, as determined by its morphology, the unfavorable effect of sulphation is more pronounced. Unfortunately, any increase in the temperature in the carbonation stage accelerates sulphation more than carbonation as a result of higher activation energy for the sulphation reaction. The SEM analyses showed that although sulphation and carbonation occur during cycles involving calcination, an unreacted core/partially sulphated shell sorbent particle pattern is formed. The main outcomes of this research indicate that special attention should be paid to the sulphation when more reactive and more expensive, synthetic CaO-based sorbents are used for CO(2) capture looping cycles. Desulphurization of flue gas before CO(2) capture appears to be essential because CO(2) looping cycles are so strongly affected by the presence of SO(2).

Sulfation Performance of CaO-Based Pellets Supported by Calcium Aluminate Cements Designed for High-Temperature CO2 Capture

CaO-based sorbents supported by calcium aluminate cements were originally prepared as sorbents for CO2 capture in looping cycles. However, their high affinity for CO2 at high temperatures suggests that they will readily react with any SO2 present in flue gases to be decarbonated. Thus, the sulfation performance of these pellets was investigated in this study using a synthetic flue gas in a thermogravimetric analyzer (TGA). The results obtained showed that after 6 h in gas containing 0.5% SO2 at 900 °C the pellets prepared from hydrated lime and cement were >90% sulfated. They showed the highest sulfation affinity among the sorbents tested here. Namely, Cadomin limestone was <30% sulfated and the corresponding hydrated lime <70%. The pellets prepared from limestone powder and cement had significantly lower sulfation (∼65%) in comparison to that for pellets obtained from hydrated lime and cement. The scanning electron microscope (SEM) images of sulfated samples clearly showed the presence of a sulfated shell at the surface of original limestone particles, while the calcium aluminate pellets had porous morphology even after almost 100% sulfation. The X-ray diffraction (XRD) analyses showed that mayenite (Ca12Al14O33), which is responsible for the good CO2 capture performance of these pellets, was not present after sulfation. Pellets after 30 carbonation/calcination cycles displayed significantly reduced affinity for SO2, with sulfation conversions at ∼15%, but they easily recovered this capacity with ∼80% sulfation levels after hydration. These results clearly show that, for the pellets to perform well, the presence of SO2 must be avoided during looping cycles at least during sorbent regeneration at high temperatures.

Effect of flue gas components on succinate production and CO2 fixation by metabolically engineered Escherichia coli

Escherichia coli pfl ldhA ptsG (AFP111) was studied for succinate production in defined medium using trace gases typically found in flue gas; i.e. oxygen (O2), nitrogen dioxide (NO2), sulfur dioxide (SO2) and carbon monoxide (CO). Following aerobic cell growth, cells were exposed to 50% CO2 and 3–10% O2, or 50–300 ppm NO2, SO2 or CO during the succinate production phase. Although 3% O2 did not significantly affect succinate formation, 10% O2 reduced the final succinate concentration from 33 to 17 g/L, specific productivity from 1.90 to 1.13 mmol/g h and yield from 1.15 to 0.81 mol/mol glucose. The effect of O2 correlated with the culture redox potential (ORP) with more reducing conditions favoring succinate production. The trace gases NO2 and SO2 also reduced the rate of succinate formation by as much as 50%, and led to a greater than twofold increase in pyruvate formation. Similar concentrations of CO showed no effect on succinate production rate or yield. Using synthetic flue gas AFP111 generated 12 g/L succinate with a specific productivity of 0.73 mmol/g h and a yield of 0.65 mol/mol.

Purification of oxyfuel-derived CO 2

Oxyfuel combustion in a pulverised fuel coal-fired power station produces a raw CO 2 product containing contaminants such as water vapour plus oxygen, nitrogen and argon derived from the excess oxygen for combustion, impurities in the oxygen used, and any air leakage into the system. There are also acid gases present, such as SO 3, SO 2, HCl and NO x produced as byproducts of combustion. At GHGT8 (White and Allam, 2006) we presented reactions that gave a path-way for SO 2 to be removed as H 2SO 4 and NO and NO 2 to be removed as HNO 3. In this paper we present initial results from the OxyCoal-UK project in which these reactions are being studied experimentally to provide the important reaction kinetic information that is so far missing from the literature. This experimental work is being carried out at Imperial College London with synthetic flue gas and then using actual flue gas via a sidestream at Doosan Babcock's 160 kW coal-fired oxyfuel rig. The results produced support the theory that SO x and NO x components can be removed during compression of raw oxyfuel-derived CO 2 and therefore, for emissions control and CO 2 product purity, traditional FGD and deNO x systems should not be required in an oxyfuel-fired coal power plant.

Investigations on bromine corrosion associated with mercury control technologies in coal flue gas

Mercury control technologies are often associated with adding halogens to the flue gas to enhance oxidation of elemental mercury. The present research was to evaluate the corrosion characteristics of iron in a flue gas containing bromine to simulate mercury control applications in coal-fired utility plants. An AISI 1008 cold rolled steel was exposed to a synthetic flue gas (7.1 vol% O 2, 14.3 vol% CO 2, 2.0 vol% H 2O, 51 ppmv HBr, 510 ppmv SO 2, 51 ppmv NO x , and the balance N 2). Exposure times ranged from 30 days to 6 months. Metal coupons were exposed with simulated flue gases at 300°, 150°, and 80 F (149°, 66°, and 27 °C), respectively. The corroded coupons were analyzed using scanning electron microscope and micrometer measurements to determine the deposit chemistry and corrosion loss. The corrosion products consisted mainly of iron oxides and iron bromide. A mechanism for HBr corrosion is suggested. Bromine dew point corrosion took place on metal surfaces at temperatures below or close to the dew point of HBr, while active oxidation occurred at higher temperatures.