Anion-Exchange Resin-Based Desulfurization and Dechlorination of Spent Sorbent Material

Abstract

Emissions of acid gases such as SO₂ and HCI/CI₂ from energy conversion or waste incineration facilities are unacceptable. Under the various regulations, the emissions of such acid gases are regulated by the U.S. Environmental Protection Agency (EPA). Alkali metal sorbents can remove these acid gases more efficiently than the lime/limestone type sorbents used in the conventional flue gas desulfurization (FGD) systems. However, the resulting alkali metal sulfate and chloride are unsuitable for landfill disposal because they are water-soluble and can potentially leach into groundwater, altering the soil pH. Replacing the (virgin) sorbent material is expensive. Hence, it is desirable that the spent sorbent materials obtained from such emissions control systems be converted to sulfur- and chlorine-free forms, so that they can be reused. The weak-base, anionexchange resin-based desulfurization concept, developed and tested at the University of Tennessee Space Institute (UTSI), can also simultaneously remove sulfur- and chlorine- containing species from such spent sorbent materials. Under the U.S. Department of Energy’s (DOE) sponsorship, bench scale studies have been carried out at UTSI to evaluate the feasibility of removing sulfur- and chlorine-containing species using this resin-based concept. Efforts have also been made to enhance the candidate resins’ performance by carrying out the resin exhaustion step under CO₂ static pressure and by using suitable pH buffering agents, such as low-molecular weight organic acids. Preliminary cost estimates for a regeneration scheme employing reactivated alkali metal-based spent sorbent material using the ion-exchange resin-based concept seem attractive and comparable to currently available options. After further development, this low-cost, simple process can be easily integrated into alkali metal sorbent-based flue gas desulfurization and acid gas emission control systems.     

Status of the DOE/GEESI In-Duct Scrubbing Pilot Study

The recent promulgation of stack height regulations and possible changes in the National Ambient Air Quality Standards for sulfur dioxide and the associated dispersion model methodologies, could require older power plants to develop new compliance strategies and upgrade emission control systems. In such situations, an inexpensive, moderate removal efficiency flue gas desulfurization technology could maintain the cost effectiveness of these plants. Such a technology was selected by the Department of Energy for demonstration in its Acid Rain Precursor Control Technology Initiative. The process applies the rotary atomizer techniques developed for lime slurry dry flue gas desulfurization spray absorbers, and utilizes existing ductwork and particulate collectors. This induct scrubbing technology is anticipated to result in a dry desulfurization process of moderate removal efficiency. The critical elements for successful application are (i) adequate mixing for efficient reactant contact, (ii) sufficient residence time to produce a non-wetting product, and (iii) appropriate ductwork cross sectional areas to prevent deposition of reaction products before drying. The ductwork in many older power plants, previously modified to meet 1970 Clean Air Act requirements for particulate control, usually meets these criteria. A pilot study of the process is now in design-construct phase. Testing will start in 1987 and determine conditions under which the technology would be a cost effective approach to meeting emission reduction design criteria     

络合铁法脱除垃圾填埋气中的H2S

建立了以EDTA和柠檬酸为铁盐络合剂的循环脱硫体系，采用络合铁法对垃圾填埋气中的H₂S进行脱硫中试实验，结果表明实验所建立的络合铁脱硫体系运行稳定，脱硫效率高，适合应用于垃圾填埋气中硫化氢脱除。     

生活污水不同进水C/N比负荷对垂直潜流式人工湿地排放温室气体的影响

人工湿地处理的生活污水含氮量或者有机物含量很高时,可能会造成人工湿地在处理污水的过程中排放大量温室气体。研究了垂直潜流式人工湿地在人工合成的生活污水不同污染物进水C/N负荷条件下污水处理效果和温室气体(CO2和CH4)的排放量,利用现场测量和碳平衡模型估算分析了可以达到最佳污水净化效果和最少温室气体排放量的污染物进水C/N负荷条件。结果显示,在进水C/N负荷为C/N=6∶1~9∶1时可以得到最佳的污染物去除率。温室气体CH4排放量较CO2排放量可以忽略不计,而在进水C/N负荷为C/N=3∶1~6∶1时可以实现最少的温室气体排放。综上所述,最优的进水C/N负荷确定为C/N=6∶1,此时人工湿地可以得到较高的污染物去除率而排放较少的温室气体。     

Formation of secondary inorganic aerosols by power plant emissions exhausted through cooling towers in Saxony

Background, aim, and scope  The fraction of ambient PM₁₀ that is due to the formation of secondary inorganic particulate sulfate and nitrate from the emissions of two large, brown-coal-fired power stations in Saxony (East Germany) is examined. The power stations are equipped with natural-draft cooling towers. The flue gases are directly piped into the cooling towers, thereby receiving an additionally intensified uplift. The exhausted gas-steam mixture contains the gases CO, CO₂, NO, NO₂, and SO₂, the directly emitted primary particles, and additionally, an excess of ‘free’ sulfate ions in water solution, which, after the desulfurization steps, remain non-neutralized by cations. The precursor gases NO₂ and SO₂ are capable of forming nitric and sulfuric acid by several pathways. The acids can be neutralized by ammonia and generate secondary particulate matter by heterogeneous condensation on preexisting particles. Materials and methods  The simulations are performed by a nested and multi-scale application of the online-coupled model system LM-MUSCAT. The Local Model (LM; recently renamed as COSMO) of the German Weather Service performs the meteorological processes, while the Multi-scale Atmospheric Transport Model (MUSCAT) includes the transport, the gas phase chemistry, as well as the aerosol chemistry (thermodynamic ammonium–sulfate–nitrate–water system). The highest horizontal resolution in the inner region of Saxony is 0.7 km. One summer and one winter episode, each realizing 5 weeks of the year 2002, are simulated twice, with the cooling tower emissions switched on and off, respectively. This procedure serves to identify the direct and indirect influences of the single plumes on the formation and distribution of the secondary inorganic aerosols. Results and conclusions  Surface traces of the individual tower plumes can be located and distinguished, especially in the well-mixed boundary layer in daytime. At night, the plumes are decoupled from the surface. In no case does the resulting contribution of the cooling tower emissions to PM₁₀ significantly exceed 15 μgm⁻³ at the surface. These extreme values are obtained in narrow plumes on intensive summer conditions, whereas different situations with lower turbulence (night, winter) remain below this value. About 90% of the PM₁₀ concentrations in the plumes are secondarily formed sulfate, mainly ammonium sulfate, and about 10% originate from the primarily emitted particles. Under the assumptions made, ammonium nitrate plays a rather marginal role. Recommendations and perspectives  The analyzed results depend on the specific emission data of power plants with flue gas emissions piped through the cooling towers. The emitted fraction of ‘free’ sulfate ions remaining in excess after the desulfurization steps plays an important role at the formation of secondary aerosols and therefore has to be measured carefully.     

Application of the Active Soda Process for Removing Sulphur Dioxide from Flue Gases

The active soda process1 was applied for desulfurlzatlon of flue gases emitted by a plant burning heavy fuel oil In a rotary drum drier for stone aggregate. The flue gas capacity of the plant was about 6,7 m³/s at normal conditions. The SO₂ concentration varied between 400– 500 ppm. The solid, dry and fine-grained NaHCO₃ of good quality was fed directly into the hot gas stream at the outlet of the rotary drier In two variants—with and without grinding. The mean particle size was 0.180 m^-3 or 0.070 m^-3, respectively. The achieved desulfurizatlon degree was shown to be directly dependent on the flue gas temperature and on the grinding effect, as well as on the normalized stoichiometric ratio. The highest achieved desulfurization degree amounted up to 74 percent. During the design of the desulfurization process no pilot plant installations and tests were necessary, and for the final process no special chemical reactor was used.     

The Fate and Behavior of Mercury in Coal-Fired Power Plants

Abstract

For the past 22 years in the Netherlands, the behavior of Hg in coal-fired power plants has been studied extensively. Coal from all over the world is fired in Dutch power stations. First, the Hg concentrations in these coals were measured. Second, the fate of the Hg during combustion was established by performing mass balance studies. On average, 43 ± 30% of the Hg was present in the flue gases downstream of the electrostatic precipitator (ESP; dust collector). In individual cases, this figure can vary between 1 and 100%. Important parameters are the Cl content of the fuel and the flue gas temperature in the ESP. On average, 54 ± 24% of the gaseous Hg was removed in the wet flue-gas desulfurization (FGD) systems, which are present at all Dutch coal-power stations. In individual cases, this removal can vary between 8% (outlier) and 72%.

On average, the fate of Hg entering the power station in the coal was as follows: <1% in the bottom ash, 49% in the pulverized fuel ash (ash collected in the ESP), 16.6% in the FGD gypsum, 9% in the sludge of the wastewater treatment plant, 0.04% in the effluent of the wastewater treatment plant, 0.07% in fly dust (leaving the stack), and 25% as gaseous Hg in the flue gases and emitted into the air. The distribution of Hg over the streams leaving the FGD depends strongly on the installation. On average, 75% of the Hg was removed, and the final concentration of Hg in the emitted flue gases of the Dutch power stations was only ~3 μg/m_STP ³ at 6% O₂. During co-combustion with biomass, the removal of Hg was similar to that during 100% coal firing.

Speciation of Hg is a very important factor. An oxidized form (HgCl₂) favors a high degree of removal. The conversion from Hg⁰ to HgCl₂ is positively correlated with the Cl content of the fuel. A catalytic DENOX (SCR) favors the formation of oxidized Hg, and, in combination with a wet FGD, the total removal can be as high as 90%.     

Removal of NOx from Flue Gas with Iron Filings Reduction Following Complex Absorption in Ferrous Chelates Aqueous Solutions

Abstract

A novel process for removal of nitrogen oxides (NO_x) from flue gases with iron filings reduction following complex absorption in iron-ethylenediaminetetraacetic acid aqueous solution is proposed. The reaction mechanism involved in the process is discussed briefly. The parameters influencing the process, including the concentration of ferrous chelates, initial pH, amount of iron filings, temperature, flow rate of the flue gas, and inlet nitric oxide concentration and oxygen content of the flue gas, are researched in detail. The optimal NO_x removal conditions are established. The regeneration and circular utilization of the absorption solution also is studied.     

The Use of Nahcolite Ore and Bag Filters For Sulfur Dioxide Emission Control

This paper describes some technical and economic aspects of the nahcolite ore injection process for the simultaneous removal of fly ash and sulfur oxides from stack gases. The process is capable of removing greater than 99% of the particulate matter and greater than 70% of the sulfur oxides present in such gases. In the process, nahcolite ore, a naturally occurring material containing 70 to 90% sodium bicarbonate, is ground to 90% passing through —200 mesh screens. Approximately 20% of the ground ore is used to precoat the filter bags in a baghouse filter while the remainder of the material is fed into the flue gas Just ahead of the baghouse. The flue gas is drawn through the baghouse by induced draft fans and sent up the stack. Most of the SO₂ and practically all of the fly ash in the flue gas can be removed as the gas passes through the filter bags. The spent nahcolite ore and fly ash are collected and conveyed to waste disposal as landfill, or alternatively processed for insolubilization by coprecipitation prior to landfilling. The technical feasibility of the process has been demonstrated in both bench scale and pilot scale engineering studies. Economic analyses performed for the cases of plants located in the midwest and southwest indicate lower capital costs for the nahcolite injection process when compared to wet scrubbing. On an annual cost basis, the nahcolite ore Injection process is comparable in cost to wet scrubbing for the case of the southwestern power plant, and somewhat more expensive for the case of the midwestern plant.     

Simulation of Stack Plume Opacity

ABSTRACT

The visual impact of primary particles emitted from stacks is regulated according to stack opacity criteria. In-stack monitoring of the flue gas opacity allows plant operators to ensure that the plant meets U.S. Environmental Protection Agency opacity regulations. However, the emission of condensable gases such as SO₃ (that hydrolyzes to H₂SO₄), HCl, and NH₃, which may lead to particle formation after their release from the stack, makes the prediction of stack plume opacity more difficult.

We present here a computer simulation model that calculates the opacity due to both primary particles emitted from the stack and secondary particles formed in the atmosphere after the release of condensable gases from the stack. A comprehensive treatment of the plume rise due to buoyancy and momentum is used to calculate the location at which the condensed water plume has evaporated (i.e., where opacity regulations apply).

Conversion of H₂SO₄ to particulate sulfate occurs through nucleation and condensation on primary particles. A thermodynamic aerosol equilibrium model is used to calculate the amount of ammonium, chloride, and water present in the particulate phase with the condensed sulfate. The model calculates the stack plume opacity due to both primary and secondary particles. Examples of model simulations are presented for three scenarios that differ by the emission control equipment installed at the power plant: (1) electrostatic precipitators (ESP), (2) ESP and flue gas desulfurization, and (3) ESP and selective catalytic reduction. The calculated opacity is most sensitive to the primary particulate emissions. For the conditions considered here, SO₃ emissions showed only a small effect, except if one assumes that most H₂SO₄ condenses on primary particles. Condensation of NH₄Cl occurs only at high NH₃ emission rates (about 25 ppm stack concentration).     

Nitrogen Dioxide Detection Using a Coulometric Method

Recent developments in SO₂ removal from combustion gases by dry techniques in this country and abroad are reviewed. Process flow-sheets, operating conditions, by-product yields, and relative costs of a purification system for an 800-megawatt powerplant are discussed.     

Advanced Concepts in FGD Technology: The SHU Process with Cooling Tower Discharge

The growing awareness of ecological issues in Europe, reinforced by the public debate surrounding acid rain, has led to the enactment of laws and regulations in West Germany relating to emissions from large coal fired combustors.

Flue gas desulfurization (FGD) units have been compulsory for new coal fired power plants in West Germany for about 12 years. The new legislation enacted in 1983, to be met by the middle of 1988, applies not only to new plants but, unlike in the United States, also to. existing power plants (>30MW).

The law currently specifies a residual SO2 emission level of 400 mg/Nm³ (0.311b MM/BTU) for large power plants (>100 MW), but a level of 200 mg/Nm³ (0.15 lb MM/BTU) is already under discussion in some cases. The legally binding emission standards stipulate that none of the daily averages, calculated on the basis of half hour averages may exceed the concentration allowed. SO2 removal efficiencies of 90 percent to 95 percent are normally provided. Since 1983, more than 35,000 MW of retrofit FGD units have been installed in Germany to meet this SO₂ standard.

The regulations also do not allow for the ponding of calcium sulfite scrubber sludge, but stipulate the production of gypsum from limestone slurry processes. Additionally the regulations require flue gases to have a minimum temperature in the stack of 72° C (162°F) after desulfurization. Treated flue gases do not have to be reheated if discharged via a cooling tower.     

酸碱改性对氧化铁脱硫剂脱硫性能影响的研究

通过酸碱改性制备了酸式和碱式2种不同表面性质的常温氧化铁脱硫剂,并采用FT-IR技术对其表面酸碱性质和净化硫化氢废气活性进行了研究.结果表明,表面酸碱件质不同的脱硫剂其脱硫反应行为也不同,在脱硫过程中硫化氢氧化生成的硫酸及亚硫酸会影响脱硫剂的表面酸碱性质,造成酸式脱硫剂的表面酸性更强,从而抑制了硫化氢分子在酸式脱硫剂表...     

Index

Abstract

Activated carbon (AC) adsorption has long been considered to be a readily available technology for providing protection against exposure to acutely toxic gases. However, ACs without chemical impregnation have proven to be much less efficient than impregnated ACs in terms of gas removal. The impregnated ACs in current use are usually modified with metalloid impregnation agents (ASC-carbons; copper, chromium, or silver) to simultaneously enhance the chemical and physical properties of the ACs in removing specific poisonous gases. These metalloid agents, however, can cause acute poisoning to both humans and the environment, thereby necessitating the search for organic impregnation agents that present a much lower risk. The aim of the study reported here was to assess AC or ASC-carbon impregnated with triethylenediamine (TEDA) in terms of its adsorption capability for simulated hydrogen sulfide (H₂S) and sulfur dioxide (SO₂) gases. The investigation was undergone in a properly designed laboratory-scale and industrial fume hood evaluation. Using the system reported here, we obtained a significant adsorption: the removal capability for H₂S and SO₂ was 375 and 229 mg/g-C, respectively. BET measurements, element analysis, scanning electron microscopy, and energy dispersive spectrometry identified the removal mechanism for TEDA-impregnated AC to be both chemical and physical adsorption. Chemical adsorption and oxidation were the primary means by which TEDA-im pregnated ASC-carbons removed the simulated gases.     

石灰石高温煤气脱硫的试验研究

采用天然石灰石做脱硫剂，在固定床上进行硫化氢高温脱除的试验研究，考察了脱硫剂粒径、反应温度、气速及高温煤气中H2对石灰石脱硫性能的影响，同时还用热重分析(TG)、扫描电镜(SEM)、X-射线衍射(XRD)等测试手段对脱硫剂的物相组成和结构等进行了表征。结果表明，脱硫剂的粒径对脱硫效果的影响很大，0.38～0.83 mm的石灰石脱硫效果最佳；温度对脱硫效果的影响比较复杂，最佳的操作温度为850℃；气速对脱硫效果的影响较明显，脱硫剂的穿透时间随气速的减小而加长；H₂对脱硫过程起阻碍作用，气速越小，这种阻碍作用越明显。     

Performance and Problems of Claus Plant Operation on Coke Oven Acid Gases

The application of Claus Plant sulfur recovery units to the coke oven gas (COG) acid gases at three Bethlehem Steel Corporation plants is discussed. While many of the problems encountered are not unique to coke oven gas-derived acid gases, it was found that special consideration must be given to the effect of components not normally encountered in the typical Claus plant application to petroleum derived gases. It is perhaps fortunate that the feed composition to the three units was sufficiently different to expedite recognition of the source of some of these difficulties. One substance of concern is the hydrogen cyanide normally found in COG acid gases. In the absence of some means of removing or decomposing this material before it enters the Claus Plant extensive corrosion within the unit is observed after a short period of time. This is due to the fact that, contrary to expectation, a substantial quantity of this material survives the burner flame. The various alternatives in its elimination are discussed. A second major contaminant in COG acid gases is particulate iron sulfide and iron cyanide. While the exact source of these materials is in doubt, there is little doubt that in the absence of their removal, inorganic blockages within the Claus Plant will occur. By properly accounting for the special properties of coke oven gas-derived acid gas we have recently achieved short term sulfur recovery efficiencies of 95% and higher.     

Fenton氧化法同时脱硫脱硝的实验研究

应用Fenton液相氧化吸收法进行同时脱硫脱硝实验。首先,利用单因素实验,分别考察了H2O2浓度、Fe2+投加量、初始pH值、UV照射和温度对脱硫脱硝的影响。结果表明,SO2和NO去除率随着H2O2浓度和Fe2+投加量的增大而提高;初始pH对SO2和NO的去除有较大影响;UV能促进SO2和NO的净化;温度对脱硫效率影响不大,但对NO的去除有显著作用,适当升温可以提高脱硝效率。随后,考察了SO2对NO去除率的影响。通过单独脱硝和同时脱硫脱硝的对比实验发现,SO2的加入对NO的去除有一定的促进作用,Fenton法可同时获得起始约80%的脱硝效率和98%以上的脱硫效率。     

Minnesota Power’s Operating Experience with Integrated Particulate and SO2 Scrubbing

Minnesota Power currently has in commercial operation a 500 MW gas cleaning system consisting of a venturi particulate scrubber, integrated with a spray tower SO₂ absorber. The system was designed to achieve 99.7% particulate removal and 90% SO₂ removal based upon burning a 2.8 % sulfur coal.

Initially the concept of using a venturi for wet particulate collection was selected based upon a significant cost saving of $25 million compared to dry particulate collection devices. Subsequently, the Interaction of particulate collection with SO₂ removal provided additional operating cost benefits. Prior to start-up of the commercial system, a pilot plant was used to evaluate various modes of operation. Results showed that alkali contained in the fly ash removed with the venturi was sufficient to meet the alkali requirement for SO₂ removal.

Clay Boswell Station Unit No. 4 was started up during March 1980. Since initial start-up the system has exhibited almost 100% availability. EPA compliance testing has confirmed that the system Is meeting its emission standards. The unit is operating with fly ash as the only source of alkali. Since commercial operation started, no external alkali has been purchased.

This paper will discuss the design details of the system and performance of the commercial system.     

Fine Particle Control Using Sulfur Oxide Scrubbers

Compliance with sulfur oxides standards will in many cases result in the installation of scrubbing devices. If these devices operate on an effluent gas stream containing particulate as well as sulfur oxides, simultaneous removal would be expected. Since effective simultaneous removal of particulate matter and sulfur oxides is economically desirable, it is of considerable import to characterize scrubber designs being considered as sulfur oxide absorbers as particulate control devices; especially, for fine particulate control.

Data on the fine particle collection efficiency of sulfur oxides scrubbers at two power generating stations is presented. At the first, a venturi and a turbulent contacting absorber (TCA) both with capacities of 30,000 cfm were tested. At the second, a venturi with 600,000 scfm capacity was tested. Fine particle collection efficiency was determined at three pressure drops for the TCA using a cascade impactor. Results for the TCA show high removal efficiencies. It collected more than 90% of submicron particles when the pressure drop was nearly 10 in. H₂0. The overall particulate removal in the TCA scrubber as determined by modified method 5 or by Brink impactor was greater than 99% when the pressure drop was greater than 6 in. H₂0. For both the venturi scrubber at the Shawnee Steam Plant and that at the Mystic Power Station, the collection efficiency decreased rapidly with decreasing particle size in the fine particle region.