Sour gases

Sour gas gas found in its natural state containing compounds of sulfur at concentrations exceeding levels for practical use because of corrosivity and toxicity. 

The practical importance of the higher sulfanes relates to their formation in sour-gas wells from sulfur and hydrogen sulfide under pressure and their subsequent decomposition which causes well plugging (134). The formation of high sulfanes in the recovery of sulfur by the Claus process also may lead to persistance of traces of hydrogen sulfide in the sulfur thus produced (100). Quantitative deteanination of H2S and H2S in Claus process sulfur requires the use of a catalyst, eg, PbS, to accelerate the breakdown of H2S (135). 

Other components in the feed gas may react with and degrade the amine solution. Many of these latter reactions can be reversed by appHcation of heat, as in a reclaimer. Some reaction products cannot be reclaimed, however. Thus to keep the concentration of these materials at an acceptable level, the solution must be purged and fresh amine added periodically. The principal sources of degradation products are the reactions with carbon dioxide, carbonyl sulfide, and carbon disulfide. In refineries, sour gas streams from vacuum distillation or from fluidized catalytic cracking (FCC) units can contain oxygen or sulfur dioxide which form heat-stable salts with the amine solution (see Fluidization Petroleum). 

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. 

Sulfide Stress Cracking) on steels over Rockwell C 22. (4) static stresses. other equipment handling sour gas, oil and/or water wherein H2S and H2O (liquid phase) are present up to about 150 F, where sulfide stress cracking slows down perceptibly. stainless steels with Rockwell hardness over C 22. (4) into crystal structure, exact mechanism uncertain. Sulfur expedites absorption of atomic H into grain structure. (4) if feasible use inhibitors and/or resistant coatings where feasible time or heating up will permit H to diffuse out but will not relieve any areas when H2 has concentrated. 

Pitting in Amine Service. In the early 1950s the increased use of natural gas from sour gas areas multi-... 

Vulcanisation can be effected by diamines, polyamines and lead compounds such as lead oxides and basic lead phosphite. The homopolymer vulcanisate is similar to butyl rubber in such characteristics as low air permeability, low resilience, excellent ozone resistance, good heat resistance and good weathering resistance. In addition the polyepichlorohydrins have good flame resistance. The copolymers have more resilience and lower brittle points but air impermeability and oil resistance are not so good. The inclusion of allyl glycidyl ether in the polymerisation recipe produces a sulphur-curable elastomer primarily of interest because of its better resistance to sour gas than conventional epichlorhydrin rubbers. 

The delayed coking feed stream of residual oils from various upstream processes is first introduced to a fractionating tower where residual lighter materials are drawn off and the heavy ends are condensed. The heavy ends are removed and heated in a furnace to about 900 to 1,000 F and then fed to an insulated vessel called a coke drum where the coke is formed. When the coke drum is filled with product, the feed is switched to an empty parallel drum. Hot vapors from the coke drums, containing cracked lighter hydrocarbon products, hydrogen sulfide, and ammonia, are fed back to the fractionator where they can be treated in the sour gas treatment system or drawn off as intermediate products. 

Leahey, D.M. and M.J.E. Davies, 1984. Observations of Plume Rise from Sour Gas Flares. Atmospheric Environment, 18, 917-922. Misra, P.K. and S. Onlock, 1982. Modelling Continuous Fumigation of Nanticoke Generating Station Plume. Atmospheric Environment, 16, 479-482. 

Continuous releases of concentrated HjS streams must be segregated in a separate flare system to limit the extent of fouling and plugging problems. Releases of HjS such as diversion of sour gas product to flares during shutdown or upset of a downstream sulfur recovery unit are considered to be continuous, but safety valve releases are not included in this category. However, if a special HjS flare system is provided for continuous releases, the concentrated HjS safety valve releases should be tied into it rather than into the regular flare system. Due to the nature of HjS one should plan on frequent inspection and flushing of HjS flares to remove scale and corrosion products. 

Another proeess where the employer might eonsider using a generie type of PHA is a gas plant. Often these plants are simply moved from site to site, and therefore, a generie PHA may be used for these movable plants. Also, when an employer has several similar size gas plants and no sour gas is being proeessed at the site, a generie PHA is feasible as long as the variations of the individual sites are aeeounted for in the PHA. 

Natural gas with H2S or other sulfur compounds present is called sour gas, while gas with only CO2 is called sweet. Both H2S and CO2 are undesirable, as they cause corrosion and reduce the heating value and thus the sales value of the gas. In addition, H2S may be lethal in very small quantities. Table 7-1 shows physiological effects of H2S concentrations in air. 

The ferric oxide is impregnated on wood chips, which produces a solid bed with a large ferric oxide surface area. Several grades of treated wood chips are available, based on iron oxide content. The most common grades are 6.5-, 9.0-, 15.0-, and 20-lb iron oxide/bushel. The chips are contained in a vessel, and sour gas flows through the bed and reacts with the ferric oxide. Figure 7-3 shows a typical vessel for the iron sponge process. 

A typical amine system is shown in Figure 7-4. The sour gas enters the system through an inlet separator to remove any entrained water or hydrocarbon liquids. Then the gas enters the bottom of the amine absorber and flows counter-current to the amine solution. The absorber can be either a trayed or packed tower. Conventional packing is usually used for 20-in. or smaller diameter towers, and trays or structured packing for larger towers. An optional outlet separator may be included to recover entrained amines from the sweet gas. 

In summation, MEA systems can efficiently sweeten sour gas to pipeline specifications however, great care in designing the system is required to limit equipment corrosion and MEA losses. 

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. 

A physical solvent process is shown in Figure 7-6. The sour gas contacts the solvent using counter-current flow in the absorber. Rich solvent from the absorber bottom is flashed in stages to a pressure near atmos... 

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-... 

The amine cooler is typically an air-cooled, fin-fan cooler, which low-er.s the lean amine temperature before it enters the absorber. The lean amine entering the absorber should be approximately 10°F warmer than the sour gas entering the absorber. Lower amine temperatures may cause the gas to cool in the absorber and thus condense hydrocarbon liquids. Higher temperatures would increase the amine vapor pressure and thus increase amine losses to the gas. The duty for the cooler can be calculated from the lean-amine flow rate, the lean-amine temperature leaving the rich/lean exchanger and the sour-gas inlet temperature. 

Figure 5 Comparison of HNBR with fluoroelastomer (FPM), NBR and XNBR in Sour Crude Oil (sour gas = 20% H2S + 65% CH4 + 15% CO2). Source Bayer AG, Germany.

An amine absorber (Figure 1-15) removes the bulk of H2S from the sour gas. The sour gas leaving the sponge oil absorber usually flows into a separator that removes and liquefies hydrocarbon from vapors. The gas from the separator flows to the bottom of the HjS contactor where it contacts a countercurrent flow of the cooled lean amine from the regenerator. The treated fuel gas leaves the top of the HjS absorber, goes to a settler drum for the removal of entrained solvent, and then flows to the fuel system. 

The sour gas, containing small amounts of amine, leaves the top ol the regenerator and flows through a condenser to the accumulator. The sour gas is sent to the sulfur unit, while the condensed liquid is refluxed to the regenerator. 

Martin, R. L. and French, E. C., Corrosion Monitoring in Sour Systems Using Electrochemical Hydrogen Patch Probes Conf. Soc. of Pet. Engrs. of AIME, Sour Gas Symposium, Texas, (1977)... 

Sour gas is natural gas that contains sulphur, sulphur compounds, and/or carbon dioxide in quantities that may require removal for commercial use. 

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