Sweetening of sour gas

FIGURE 11.15. Schematic diagram of a typical thermal swing process for sweetening of sour gas. (From ref. 22, copyright John Wiley Sons, Inc., 1978 reprinted with permission.) 

Where the concentrated sour gas recovered during the regeneration cycle cannot be used as fuel, or otherwise disposed of, it is sometimes further treated by absorption in ethanolamine solution. 

A particular problem in this process is the formation of COS by reaction between adsorbent COj and H2S  

The formation of COS is undesirable since it passes through the system with CO2 leaving significant sulphur in the gas and if the gas is fractionated to recover heavier hydrocarbons COS is concentrated in the propane fraction. In contact with traces of moisture the COS can be hydrolyzed back to H2S with obvious undesirable consequences. 

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The sweetening of sour gas provides a good example of a process which involves the adsorption of more than one species. A schematic of a typical system is shown in Figure 11.15. In essential features the process is similar to the simple dehydration process but the profiles of concentration and temperature through the adsorbent bed are more complicated. It is usual to use a large-pore type X sieve as the adsorbent in order to adsorb mercaptans as well as H S. 

Figure 7.9 Sweetening of sour gas stream by a thermal swing process (source Chi and Cummings 1978).

Figure 7-5 shows a typical hot carbonate system for gas sweetening. The sour gas enters the bottom of the absorber and flows counter-current to the potassium carbonate. The sweet gas then exits the top of the absorber. The absorber is typically operated at 230°F therefore, a sour/ sweet gas exchanger may be included to recover sensible heat and decrease the system heat requirements. 

The hybrid metal phthalocyanine complexes may find application for specific pollution control processes such as S02 stack-gas scrubbing, post-Klaus plant scrubbing of H2S and S02, sweetening of sour oil-refinery wastes, odor and corrosion control in wastewater facilities, and the elimination of excess rocket fuel wastes. 

The use of sour gas as feed for the process that needs to be desulfurized in Acid Gas Sweetening unit (assuming that it is merchaptans free). 

As Fig.2 and Table 1 show, increasing the flow rate of Ammonia produced by 66.6% resulted in a decrease in total plant Carbon Footprint (= 2.8 - 6.6%) considering all scenarios. Carbon Footprint of each unit increased with increased production rate except for the Ammonia Synthesis loop where this decrease occurred. A total decrease of ( 3.8 - 6%) of plant Carbon Footprint occurred when using sweet gas instead of sour gas that has to be treated first. Moreover, the utilization of HP and LP steam reduces the overall Carbon Footprint (= 12.5 - 15%). LP steam is utilized in boilers of coliimns in both Acid Gas Sweetening and CO2 Removal units. 

Conversion Processes. Most of the adsorption and absorption processes remove hydrogen sulfide from sour gas streams thus producing both a sweetened product stream and an enriched hydrogen sulfide stream. In addition to the hydrogen sulfide, this latter stream can contain other co-absorbed species, potentially including carbon dioxide, hydrocarbons, and other sulfur compounds. Conversion processes treat the hydrogen sulfide stream to recover the sulfur as a salable product. 

Sour gas sweetening may also be carried out continuously in the flowline by continuous injection of H2S scavengers, such as amine-aldehyde condensates. Contact time between the scavenger and the sour gas is the most critical factor in the design of the scavenger treatment process. Contact times shorter than 30 sec can be accommodated with faster reacting and higher volatility formulations. The amine-aldehyde conden-... 

If the natural gas stream contains unacceptable quantities of hydrogen sulfide and/or carbon dioxide, they must be removed in order to make the gas suitable for transmission and sale. The details of removal of H2S and C02 from natural gas streams are beyond the scope of this chapter, but excellent discussions are available.10,12 There are many different processes available, depending upon the contaminants to be removed and their concentration in both the sour gas available and the sweetened gas to be produced. The dominant treating process is still the use of an alka-nolamine. A typical flow diagram for an amine sweetening installation for removal of hydrogen sulfide and carbon dioxide from a natural gas stream is shown in Fig. 20.10.12... 

Maddox, R.N. 1974 edition. Gas and liquid sweetening. John M. Campbell Ltd. 39-42, and Maddox, R.N., L.L. Lilly, M. Moshfeghian, and E. Elizondo. 1988. Estimating water content of sour natural gas mixtures. Laurance Reid Gas Conditioning Conference, Norman, OK, March. 

FIGURE 9.6 Flowsheet giving the schematic details of Girbotol and related sour gas sweetening processes. Twenty to twenty-four plates are used in the absorbers and strippers [25] for efficient contacting and desorption with monoethanolamine (MEA),... 

The cost of acid gas removal depends strongly on its concentration and the need for downstream compression. In the case of very sour gas the combination of a bulk removal step ahead of the final sweetening unit can reduce the overall add gas removal cost. If the acid gas is re-injeded the bulk removal process should offer... 

Tn 1972 Alberta produced 8 X 106 long-tons of elemental sulfur by sweetening sour gas (I), i.e., a natural gas containing an appreciable amount of hydrogen sulfide. Hydrogen sulfide and other sulfur compounds are converted to sulfur by the well known modified Claus process using alumina-based catalysts. The basic chemical reactions are ... 

The processes are basically the same with little variation in flow scheme. The sour gas containing HaS and/or COa enters the plant through a scrubber, which removes any free liquids and/or entrained solids. The sour gas then enters the bottom of the absorber and flows upward in countercurrent contact with the descending aqueous amine solution. Sweetened gas leaves the top of the absorber and flows to a dehydration unit, where saturation water from the aqueous amine solution is removed. 

Elemental sulfur1-4 occurs naturally in association with volcanic vents and, in Texas and Louisiana, as underground deposits. The latter are mined by injecting air and superheated water, which melts the sulfur and carries it to the surface in the return flow (the Frasch process). Most of the sulfur used in industry, however, comes as a by-product of the desulfurization of fossil fuels. For example, Albertan sour natural gas, which often contains over 30% (90%, in some cases) hydrogen sulfide (H2S), as well as hydrocarbons (mainly methane) and small amounts of C02, carbonyl sulfide (COS), and water, is sweetened by scrubbing out the H2S and then converting it to elemental S in the Claus process.5 The Claus process is applicable in any industrial operation that produces H2S (see Section 8.5) it converts this highly toxic gas to nontoxic, relatively unreactive, and easily transportable solid sulfur. 

The amine unit is based on a 30% DEA solution. The feed gas is compressed to 285 psia and pretreated to remove heavy hydrocarbons. After passing through the DEA absorber, the sweet offgas is compressed to 650 psia and sent to the existing gas plant. The sour CO2 stream from the DEA stripper, at 20 psig, is compressed to 450 psia and sent to a Selexol sweetening process designed to reduce the H2S content of the CO2 product gas to less than 100 ppm. 

Natural Gasoline. Even though gas desulfurization as by the use of monoethanolamine or other agents (see Table 22-4 and Fig. 20-18) is practiced for the removal and/or recovery of hydrogen sulfide from the gas, it is still necessary to sweeten the liquid products and to dry the propane. With especially sour products, the system indicated by M. H Rahmes (see Fig, 10-7) is extensively used. If the mercaptan content... 

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