Sulfur recovery plant

Bromine All of the bromine produced in the United States is extracted from naturally occurring brines by steam extraction. The major air pollution concern is H2S from the stripper if H2S is present in the brine. The H2S can either be oxidized to SO2 in a flare or sent to a sulfur recovery plant. 

The Stretford Process sweetens and also produces sulfur. It is good for low feed gas concentrations of H2S. Economically, the Stretford Process is comparable to an amine plant plus a Claus sulfur recovery plant. Usually, the amine/Claus combination is favored over Stretford for large plants. Stretford can selectively remove H2S in the presence of high CO2 concentrations. This is the process used in the coal gasification example in the Introduction. 

Claus sulfur recovery plant, 23 601 Clay, 5 640. See also Clays in FCC catalysis, 11 681 as filler, 11 312... 

The generation of the required reducing gas is very expensive because natural gas or low sulfur oil are used. Both of these fuels are in short supply and do not offer long-term solutions to the problem. However, in certain industrial processes, like petroleum refineries, a reducing gas could be readily available. Also, if a Claus sulfur recovery plant existed on-site, the concentrated SO2 stream could be sent to the Claus plant where it would mix with the H2S containing gas streams. Final adjustment of the H2S S02 ratio would be necessary. If the overall sulfur balance were favorable, the need for a reducing gas could be avoided. Either of these options could make the use of a recovery process economically attractive for industrial applications. 

The Ralph M. Parsons Co. "Sulfur Recovery Plants and Tailgas Purification Units by Parsons."... 

The Claus Catalytic Cbnverters. These units represent the heart of any sulfur recovery plant. While the bulk of the sulfur yield may be obtained in the front end reaction furnace the high overall recovery levels demanded by environmental regulations are largely dependent on the efficiency of the Claus catalytic converters. 

Although the Claus catalytic conversion is a highly efficient process as presently employed in sulfur recovery plants the continuing efforts to reduce sulfur emissions to atmosphere demand that the last possible ounce of efficiency be squeezed from the process. Whether further small but critical improvements in the already high sulfur recovery efficiency can be achieved by more fine tuning of the converters and their catalyst charge remains to be seen. What cannot be accomplished in the catalytic converters will be achieved in the tail gas desulfurization processes. 

Reductive Tail Gas Treatments. It was largely as a result of the effort to achieve better than 99% recovery that the reductive tail gas desulfurization processes (46) were developed in the 1970 s. The two main methods are the Beavon Sulfur Removal (BSR) (47) and the Shell Claus Off-Gas Treatment (SCOT) (48) processes. Both of these processes are now widely used as tail gas desulfurization units on sulfur recovery plants and can readily achieve point source emission levels below 250 ppm and below 100 ppm if necessary to meet regulatory standards. 

The 140°F reflux drum temperature, shown in Fig. 10.3, is the dew point of the vapors leaving the reflux drum. Almost always, we would like to minimize this particular temperature. The lower the reflux drum temperature, the smaller the amount of steam in the off-gas. If the off-gas is H2S and NH3, flowing to a sulfur recovery plant, the steam carried into the sulfur plant reduces the sulfur plant s capacity and efficiency. 

Catalysts help customers comply cost-effectively with clean-air regulations. Hydrocarbons, carbon monoxide, and nitrogen oxides can be removed using supported precious metal catalysts. Organic sulfur compounds are converted to H2S using nickel/molybdenum or cobalt/molyb-denum on alumina catalysts. Sulfur can be recovered in a Claus process unit. The Claus catalytic converter is the heart of a sulfur recovery plant. 

The "Rectisol" or "Selexol" plant of the "selective" type absorbs both H S and C0 , but in the regeneration section of the plant the H S and CO are separated to provide two streams, one or which is CO, virtually free from H S, and the other is of a suitable CO2/H2S ratio to be processed in a conventional sulfur recovery plant. 

Figure 25.4 shows a typical sulfur recovery plant based on the Claus process. The tail gas from the Claus reactors may be further processed to remove any remaining sulfur compounds. Combined H2S removal efficiencies of 99.5-99.99 percent are achievable.20 This may be done by low-temperature Claus-type solid-bed processes (e.g., the Sulfreen process), wet-Claus absorption/oxidation processes (e.g., the Clauspol 1500 process), or hydrogenation of the off-gas to form H2S for recycle (e.g., the SCOT process). Residual sulfur compounds in the tail gas are then incinerated to S02. The residual S02 in the oxidized tail gas may be scrubbed by any of several processes (e.g., the Wellman-Lord process) before being vented to the environment. It is feasible to bring the H2S content of... 

Phosphate-rock-processing plants Coke-oven batteries Sulfur-recovery plants Carbon-black plants (furnace process)... 

Determination of total fluoride emissions from stationary sources—SPADNS zirconium lake method Determination of total fluoride emissions from stationary sources—specific ion electrode method Determination of fluoride emissions from potroom roof monitors for primary aluminum plants Determination of total fluoride emissions from selected sources at primary aluminum production facflities Determination of hydrogen sulfide, carbonyl sulfide, and carbon disulfide emissions from stationary sources Determination of total reduced sulfur emissions from sulfur recovery plants in petroleum refineries Semicontinuous determination of sulfur emissions from stationary sources Determination of total reduced sulfur emissions from stationary sources (impinger technique)... 

The major emission source in the product separation and purification operations is the sulfur recovery plant tail gas. This can contain significant levels of acid or sulfurous gases. 

Processes of this type are most frequently used for pro-cessir tail gases from Claus sulfur recovery plants, wiiich are operated to contain the correct stoichiometric proportions of hydrogen sulfide and sulfur dioxide [791. The other type of direct converaon process uses an alkaline solution (often sodium carbonate) containing one or more mild oxidizing agents that oxidize hydrogen sulfide to sulfur and are then themselves regenerated by oxidation with air [80]. 

It soon became apparent that the refinery really was in a difficult spot. The remaining sulfur recovery plant was limited to 100 tons/day (T/D) of sulfur. The refinery normally made 130 T/D. Consequently, crude run had been cut by 40,000 barrels per day (B/D) to avoid emitting sulfur pollutants to the atmosphere. The daily penalty was huge, several times my total annual salary. 

Limited As soon as any operator uses the word limited, the troubleshooter should respond, "Which piece of process equipment is limiting plant capacity " After some evasion, the foreman referred me to the chief operator, who would be able "to answer my question in more detail." (The psychology of dealing with chief operators is a subject unto itself, as mentioned in Chapter 30. Suffice it to say that utmost diplomacy is always warranted.) The chief came right to the point. The sulfur recovery plant was limited by front-end pressure. The hydrogen-sulfide feed gas (H2S) would spill to the flare whenever the pressure in the feed drum exceeded 10 pounds per square inch gauge (psig). 

Figure 4-1 is a process flowsheet showing how amine solution is circulated to various refinery scrubbers to absorb H2S. The lean amine chemically combines with H2S (and unavoidably some CO2) in the scrubbers. The resulting rich amine is stripped in the regenerator. Released acid gases (H2S and CO2) are charged to the sulfur recovery plant. 

On this day the refinery was in trouble. Due to a boiler-tube failure, brought on by a combination of bad luck and poor judgment, one of the two sulfur recovery plants had suddenly shut down. With only one plant operable, refinery crude run had been reduced by 25%. Possibly as a political gesture to corporate headquarters—more likely for lack of anything better to do in a desperate situation—I was called upon to help. 

On a sulfur recovery plant, excessive tripping of the reaction furnace feed was reducing unit reliability. The process engineer was asked to investigate. He found that all of the tripping incidents were due to the low-air flow trip. When the compressed air flow dropped below 1,000 SCFM, both the hydrogen sulfide (i.e., fuel) and air flow would automatically be stopped. The trip was designed to prevent the formation of a combustible mixture in downstream vessels when air flow to the reaction furnace stopped. With no air, there would be no combustion in the furnace. 

Field experience has shown that the drum in which this separation is made has a tendency to carry over distillate into the hydrogen-rich gas. The gas is scrubbed with amine to remove hydrogen sulfide. The oil in the gas is picked up by the amine and flows to the sulfur recovery plant. On one unit such an incident resulted in a fire at the tail end of the sulfur plant. 

Standards for Performance for New Stationary Sources Petroleum Refinery Sulfur Recovery Plants." Federal Renter, 40 CFR Part 60, Vol. 41, No. 193, October 4, 1976, pp. 43-866-43,874. 

Adding tail-gas units to sulfur recovery plants... 

In October 1957, the first sulfur was recovered from oil in Canada. Laurentide Chemical and Sulfur Limited (becoming Sulconam in 1980 now owned by Chemtrade Logistics) built a recovery plant (100 tonnes per day) for 2.5 million in Montreal East, which was fed by five local refineries. The source of the crude was offshore and, therefore, the sulfur production from this site was not included in official government statistics on sulfur. In the first full year of operation, Laurentide Chemical produced 21,000 tonnes of elemental sulfur. The second such sulfur recovery plant was built by Irving Oil, in Saint John, NB, in 1960. While smaller facilities were later opened (and closed), these two sites have dominated Canadian sulfur production from oil refining. Overall, sulfur production from oil refineries in Canada has been relatively small (sulphur Ifom the oil sands is discussed below). 

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