Gases sulfur removal

Brewery gases -sulfur removal from [SULFUR REMOVAL AND RECOVERY] (Vol 23)... 

Beavon, D. K. Fleck, R. N., "Beavon Sulfur Removal Process for Claus Plant Tail Gas" Sulfur Removal and Recovery from Industrial Processes 1975, Advances in Chemistry 239. 

Conversion of carbon in the coal to gas is very high. With low rank coal, such as lignite and subbituminous coal, conversion may border on 100%, and for highly volatile A coals, it is on the order of 90—95%. Unconverted carbon appears mainly in the overhead material. Sulfur removal is faciUtated in the process because typically 90% of it appears in the gas as hydrogen sulfide, H2S, and 10% as carbonyl sulfide, COS carbon disulfide, CS2, and/or methyl thiol, CH SH, are not usually formed. 

Cmde gas leaves from the top of the gasifier at 288—593°C depending on the type of coal used. The composition of gas also depends on the type of coal and is notable for the relatively high methane content when contrasted to gases produced at lower pressures or higher temperatures. These gas products can be used as produced for electric power production or can be treated to remove carbon dioxide and hydrocarbons to provide synthesis gas for ammonia, methanol, and synthetic oil production. The gas is made suitable for methanation, to produce synthetic natural gas, by a partial shift and carbon dioxide and sulfur removal. 

The plant is designed to satisfy NSPS requirements. NO emission control is obtained by fuel-rich combustion in the MHD burner and final oxidation of the gas by secondary combustion in the bottoming heat recovery plant. Sulfur removal from MHD combustion gases is combined with seed recovery and necessary processing of recovered seed before recycling. 

The basic seed processing plant design is based on 70% removal of the sulfur contained in the coal used (Montana Rosebud), which satisfies NSPS requirements. Virtually complete sulfur removal appears to be feasible and can be considered as a design alternative to minimize potential corrosion problems related to sulfur in the gas. The estimated reduction in plant performance for complete removal is on the order of 1/4 percentage point. The size of the seed processing plant would have to be increased by roughly 40% but the corresponding additional cost appears tolerable. The constmction time for the 500 MW plant is estimated to be ca five years. 

Natural gas contains both organic and inorganic sulfur compounds that must be removed to protect both the reforming and downstream methanol synthesis catalysts. Hydrodesulfurization across a cobalt or nickel molybdenum—zinc oxide fixed-bed sequence is the basis for an effective purification system. For high levels of sulfur, bulk removal in a Hquid absorption—stripping system followed by fixed-bed residual clean-up is more practical (see Sulfur REMOVAL AND RECOVERY). Chlorides and mercury may also be found in natural gas, particularly from offshore reservoirs. These poisons can be removed by activated alumina or carbon beds. 

One of the principal aspects of refinery gas cleanup is the removal of acid gas constituents, ie, carbon dioxide, CO2, and hydrogen sulfide, H2S. Treatment of natural gas to remove the acid gas constituents is most often accompHshed by contacting the natural gas with an alkaline solution. The most commonly used treating solutions are aqueous solutions of the ethanolamines or alkah carbonates. There are several hydrogen sulfide removal processes (29), most of which are followed by a Claus plant that produces elemental sulfur from the hydrogen sulfide. 

Ammonia production by partial oxidation of hydrocarbon feeds depends to some degree on the gasification step. The clean raw synthesis gas from a Shell partial oxidation system is first treated for sulfur removal, then passed through shift conversion. A Hquid nitrogen scmbbiag step follows. 

Fixed-bed desulfuri2ation is impractical and uneconomical if the natural gas contains large amounts of sulfur. In this case, bulk sulfur removal and recovery (qv) in an acid gas absorption—stripping system, followed by fixed-bed residual cleanup is usually employed. 

A process development known as NOXSO (DuPont) (165,166) uses sodium to purify power plant combustion flue gas for removal of nitrogen oxide, NO, and sulfur, SO compounds. This technology reHes on sodium metal generated in situ via thermal reduction of sodium compound-coated media contained within a flue-gas purification device, and subsequent flue-gas component reactions with sodium. The process also includes downstream separation and regeneration of spent media for recoating and circulation back to the gas purification device. A full-scale commercial demonstration project was under constmction in 1995. 

The sulfur removed via these fixed-bed metal oxide processes is generally not recovered. Rather the sulfur and sorbent material both undergo disposal. Because the sorbent bed has a limited capacity and the sulfur is not recovered, the appHcation of these processes is limited to gas streams of limited volumetric rate having low concentrations of hydrogen sulfide. 

Minor and potential new uses for ammonium thiosulfate include flue-gas desulfurization (76,77), removal of nitrogen oxides and sulfur dioxide from flue gases (78,79), converting sulfur ia hydrocarbons to a water-soluble form (80), and converting cellulose to hydrocarbons (81,82) (see Sulfur REMOVAL AND RECOVERY). 

Gas turbine fuels can contain natural surfactants if the cmde fraction is high in organic acids, eg, naphthenic (cycloparaffinic) acids of 200—400 mol wt. These acids readily form salts that are water-soluble and surface-active. Older treating processes for sulfur removal can leave sulfonate residues which are even more powerful surfactants. Refineries have installed processes for surfactant removal. Clay beds to adsorb these trace materials are widely used, and salt towers to reduce water levels also remove water-soluble surfactants. In the field, clay filters designed as cartridges mounted in vertical vessels are also used extensively to remove surfactants picked up in fuel pipelines, in contaminated tankers, or in barges. 

Cupric ion concentration is kept at an acceptable but low level by direct air oxidation of the solution. SoHds formation from sulfides in the feed gas is also possible therefore, pretreatment for sulfur removal is required. 

In the second phase, performed at a maximum temperature of about 370°C, the sulfur and a portion of the coke are removed by combustion. The rate and exothermicity are controlled by limiting the flow of combustion gas through the catalyst. Spent base metal catalysts may have sulfur levels of from 6 to 12 wt % in the form of metal sulfides. A high degree of sulfur removal must be achieved in these first two regeneration steps to avoid the formation of sulfate on the support during the final combustion step. Such a formation causes a loss of catalyst activity. 

The gasifier for the 250 MW IGCC project in The Netherlands, scheduled to begin operation in 1993, is a 55 MW gas turbine with the balance of the power from a steam turbine. An AustraHan coal is to be used, and sulfur removal is expected to be 98.5% (95). 

Figure 13.2 MDGC-ECD chromatograms of PCB fractions from sediment samples, demonstrating the separation of the enantiomers of (a) PCB 95, (b) PCB 132, and (c) PCB 149 non-labelled peaks were not identified. Reprinted from Journal of Chromatography, A 723, A. Glausch et al, Enantioselective analysis of chiral polyclilorinated biphenyls in sediment samples by multidimensional gas cliromatography-electi on-capture detection after steam distillation-solvent exti action and sulfur removal , pp. 399-404, copyright 1996, with permission from Elsevier Science.

Future legislation will stimulate burner development in the areas of carbon monoxide, NOx and particulate generation. Techniques will include flue-gas recirculation, staged combustion, and additives to reduce the NOx and more sophisticated controls. Controls over the sulfur generated do not affect burner design greatly since the sulfur dioxide is a natural product of combustion and can only be reduced by lower fuel sulfur contents or sulfur removal from the exhaust gases. 

In many units, the light cycle oil (LCO) is the only sidecut that leaves the unit as a product. LCO is withdrawn from the main column and routed to a side stripper for flash control. LCO is sometimes treated for sulfur removal prior to being blended into the heating oil pool. In some units, a slipstream of LCO, either stripped or unstripped, is sent to the sponge oil absorber in the gas plant. In other units, sponge oil is the cooled, unstripped LCO. 

A. Hausberger I think a sulfur-tolerant catalyst would definitely be an advantage in that the requirement for critical control of the sulfur removal system would be eliminated. If you can allow some sulfur to pass on through the methanator into the product gas, the amount of reagent or regeneration cost of the sulfur removal system would be reduced. As to what level of sulfur could be tolerated, that is a hard question to answer since I don t think that there is a sulfur-tolerant catalyst. 

The most important pathway of sulfur through the atmosphere involves injection as a low-oxidation-state gas and removal as oxidation-state VI sulfate in rainwater (Fig. 13-2, paths 1, 4, 5, 6, 7, 8, 9,10,12, and 13.) Since this pathway involves a change in chemical oxidation state and physical phase, the lifetime of... 

It is well established that sulfur compounds even in low parts per million concentrations in fuel gas are detrimental to MCFCs. The principal sulfur compound that has an adverse effect on cell performance is H2S. A nickel anode at anodic potentials reacts with H2S to form nickel sulfide. Chemisorption on Ni surfaces occurs, which can block active electrochemical sites. The tolerance of MCFCs to sulfur compounds is strongly dependent on temperature, pressure, gas composition, cell components, and system operation (i.e., recycle, venting, and gas cleanup). Nickel anode at anodic potentials reacts with H2S to form nickel sulfide. Moreover, oxidation of H2S in a combustion reaction, when recycling system is used, causes subsequent reaction with carbonate ions in the electrolyte [1]. Some researchers have tried to overcome this problem with additional device such as sulfur removal reactor. If the anode itself has a high tolerance to sulfur, the additional device is not required, hence, cutting the capital cost for MCFC plant. To enhance the anode performance on sulfur tolerance, ceria coating on anode is proposed. The main reason is that ceria can react with H2S [2,3] to protect Ni anode. 

Metzinger, J., Hudgins, R. R., Silveston, P. L., Gangwal, S. K., Application of a periodically operated trickle bed to sulfur removal from stack gas. Chem. Eng. Sci. 47, 3723-3727... 

Atmospheric sulfur emissions can be minimized at source by improving the process yields and desulfurization of fuels prior to combustion. The difficulty of fuel desulfurization is solid > liquid > gas. Sulfur can be removed from emissions either as S02 or H2S. Removal of the H2S can be by ... 

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