SulFerox process

The Lo-Cat process, Hcensed by US Filter Company, and Dow/Shell s SulFerox process are additional Hquid redox processes. These processes have replaced the vanadium oxidizing agents used in the Stretford process with iron. Organic chelating compounds are used to provide water-soluble organometaHic complexes in the solution. As in the case of Stretford units, the solution is regenerated by contact with air. 

Traditionally, acid gas treatment has required two separate processes. One is to remove hydrogen sulfide and the other is to convert the concentrated hydrogen sulfide stream to sulfur. A new process called the SulFerox process, developed by Shell Oil Company and The Dow Chemical Company, now offers a single process that handles both steps. The process has high degree of flexibility and requires a smaller capital investment than the Amine/Claus process. Chelated iron compounds are the heart of the process and the chemistry allows an aqueous solution of iron in high concentrations. As a result, circulation rates are low and equipment size is very small for the capacity. Figure 5.1 shows a schematic of the SulFerox process [76]. 

Cataban Process, 804 LO-CAT Process, 805 Sulfint Process, 823 SulFerox Process, 825... 

A comparison of design parameters for a conventional amine/LO-CAT combination unit and a direct LO-CAT II plant, is presented in columns 1 and 2 of Table 9-16 (Hardison, 1991). Column 3 of this table provides equivalent information for the SulFerox process (Kwan and Childs, 1991). 

In addition, excessive chelant decarboxyiation may take piace through direct Fe + oxidation of cheiant at high operating temperatures, necessitating a high chemical make-up rate. Consequently, except in special cases, the SulFerox process solution temperature should not exceed about 140°F (Allen, 1995). To prevent hydrocarbon condensation inside the contactor, the SulFerox solution temperature is usually at least I0°F warmer than the feed gas. This limits the feed gas temperature to a maximum of 130 F. 

The overall reaction for the SulFerox process can be represented as follows ... 

In most cases, the SulFerox process utilizes either a sparged tower or a proprietary pipeline contactor design that is claimed to give high H2S removal with very short residence times and is reported to be very resistant to sulfiir plugging. The contactor type selection for a particular application is based on gas volume (acfim), available pressure drop, percent H2S removal, and required capital expenditure. 

Proper operation of the SulFerox process requires good solution maintenance procedures. It is quite important to maintain the proper levels of iron, pH, additive concentration, and solids in the circulating solution. All these solution parameters must be regularly monitored by utilizing appropriate spectro-photometric, gravimetric, and titration test... 

The SulFerox process is highly selective for hydrogen sulfide removal because carbon dioxide does not react chemically with the solution. Carbon dioxide removal is limited by the CO2 solubility in the circulating solution. When the system is operated at a pH of 8, the... 

In the SulFerox process, carbonyl sulfide can be hydrolyzed to CO2 and H2S that is then reacted to elemental sulfur. However, the hydrolysis reaction rate is quite slow, and consequently the removal rate of COS is limited by the residence time in the contactor. For this reason, it would be expected that a sparged tower absorber would be much more effective at COS removal than the other contactor types. Carbon disulfide in the feed gas is first hydrolyzed to COS and then to CO2 and H2S. The net CS2 removal efficiency is therefore less than that for COS. If the contactor has ample residence time, the SulFerox process may remove as much as 30 to 60% of the carbonyl sulfide present in the sour gas. If the unit has a short residence time contactor, the removal rate for CS2 and COS may be less than 10%. 

The SulFerox process can be used for treating either low or high pressure gas. This characteristic, plus its high H2S selectivity, makes it potentially useful for a large variety of gas treating requirements. Some of the possible applications include the treatment of... 

High Pressure Sour Natural Gas Treatment. An application of the SulFerox process for removing H2S from high pressure, high CO2 content natural gas at the No. I Mivida plant, located near Pecos, TX, was reported by Iversen et al. (1990). 

Amine Tail Gas Treating. The use of the SulFerox process for amine tail gas treating is described by Pirtle (1991). The plant is a grassroots installation processing up to 6 MMscfd of wellhead gas at 7SO-8SO psig. The sour gas to the amine treater contains about 4,000 ppmv H2S, 730 ppmv mercaptans, and 200 ppmv organic sulfur compounds (RSSR, RSR, etc.). The amine treater uses an MDEA (methyldiethanolamine) based solvent. The acid gas from the amine treater is the feed to the SulFerox unit. It contains 46 mol% H2S, 3.S mol% mercaptans, and 630 ppmv of other sulfur compounds. 

One of the process requirements was operating flexibility, since the gas quality and volume at this location can vary appreciably from day to day as shown in Table 9-24 (Buenger et al., 1991B). The air pollution permit requires 90% overall reduction of HjS going to the steam generators. The SulFerox process is capable of achieving 97% hydrogen sulfide removal. 

The sulfur-cake at the Kern County plant is made up of particles averaging about 20 microns, which is smaller than normal for the SulFerox process. This has not seriously affected the filtration properties of the elemental sulfur particulate however, the filtercake moisture content is relatively high, on the order of 25 to 35 wt%. The Kern County plant uses a rotary drum vacuum filter, while more recent SulFerox plants use pressurized feed filter presses that can provide drier filtercakes (Anon., 1994). The washed sulfur-cake at the Kem County plant contains 1,000 ppmw of iron and 7,500 ppmw of organic contaminants however, the produced sulfur qualifies for agricultural use. 

The applicability of the SulFerox process to geothermal gas clean up depends on the partition of H2S between the condensate and noncondensable gases, which depends on the level of ammonia in the steam and the condenser design. As the ammonia level rises, the amount of H2S dissolved in the steam condensate increases. This makes the SulFerox process less attractive because separate condensate treatment can be required. Since the noncondensable gases are contacted with much less water with indirect cooling than with direct contact condensation, less H2S is dissolved and a major fraction remains in the gas phase. Therefore, operating plants that have been retrofitted with surface condensers are more likely to yield improved economics when the SulFerox process is used to treat the noncondensable vent gas. 

The SulFerox process converts hydrogen sulfide into elemental sulfur, which is separated from the slurry by filtration. Sulfur quality can be influenced by contaminants in the gas stream. However, filtration, followed by melting, can usually provide a yellow sulfur product with less than 100 ppmw of iron, 500 ppmw of ash, and 1,000 ppmw of carbon. A comparison between Claus-produced sulfur and the filtercake and molten sulfur produced in the SulFerox process is shown in Table 9-26 (Van Kleeck and Morisse-Amold, 1990). As indicated earlier, direct melting without concentration of the sulfur slurry is usually not a viable process option due to contamination of the molten sulfur and high chemical losses caused by thermal degradation. 

Al-Mughiery, S. S., Mills, C., and Bowman, D., 1992, The SulFerox Process for High Pressure Natural Gas Treating, paper presented at the 1992 Liquid Redox Sulfur Recovery Conference, Austin, TX, October 4-. ... 

Anon., 1994, New equipment for the SulFerox process, Sulfur, May-June, pp. 42-45. 

Buenger, C. W. and Kushner, D. S., 1988, The Sulferox Process—Plant Design Considerations, Proceedings of the Gas Processors Association 67th Annual Convention, pp. 56-62. 

Day, K. A., and Allen, M. C., 1992, Experiences Using the Sulferox Process in Refirrery Gas Treating, paper presented at the NPRA Aiuiual Meeting, New Orleans, LA, Match. 

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