Sulfuric units, operating costs

In the United States, amendments to the Clean Air Act in November 1990 limited the amount of sulfur dioxide emissions that coal-based power uthities could produce. The cost of compliance incurred by the uthities was expected to be passed along to the power consumers. The U.S. Bureau of Mines estimated that the requirements to limit sulfur dioxide emissions would increase the operational cost of certain shicon producers by up to 0.02/kg (31). 

Flue gas scrubbing also has high capital and operating costs associated with it, but also offers PM control. An additive-only solution is almost always the least expensive option when including both capital and operating expenses for SO, reduction depending on the feed sulfur. SO, reduction additives can also be effectively used in conjunction with one of the other solution options. For example, several refiners with FCC feed hydrotreaters use a SO, reduction additive to trim the SO, emissions to the required 25 ppm level rather than to hydrotreat the FCC feed more severely or to install a flue gas scrubber. The optimum choice for a given unit is often site specific. 

In cases such as the two described, we can visualize a competitive position for LBG. Cost estimates for these "hot, dirty gas" generation systems show a fuel cost of under 3.00/million Btu in 1976 dollars. However, when a purification system for both particulate and sulfur removal is added to these small-size production units, the cost increases drastically. The average output of these small, air-blown gasifiers operating at atmospheric pressure is less than 10 tons of coal/hour. Single train purification systems can handle the gas production from as much as 5,000 tons of coal/day. It is obvious that such large systems are much less costly per unit of production than a small unit handling the gas produced from 200 to 250 tons of coal/day. 

Using a Gasoline Sulfur Reduction Catalyst (GSR) in the FCC unit. Even if only partly successful, such a strategy would reduce S at a relatively low capital cost (no new unit required) and operating costs would be minimized... 

Investment and operating requirements for the complex are presented in Table III, and in Table IV these factors have been converted into a daily processing cost exclusive of H-Oil catalyst. This latter item is speciflc to the feed in question. Unit processing costs are summarized for the various feedstocks in Table V which then shows the relationship between feed type and processing costs as well as the effect of product sulfur content on processing cost. 

The SCOT Process is competitive with other processes for reducing sulfur dioxide levels to the 200-500 ppm range. Table I shows capital and operating costs for a typical unit to serve a 100 long ton/day (LT/D) SRU operating at 94% recovery efficiency per pass. 

Description The optimum feed is the mid-fraction of FCC gasoline from 70°C-150°C. This material is fed to the GT-BTX PluS unit, which extracts the sulfur and aromatics from the hydrocarbon stream. The sulfur-plus aromatic components are processed in a conventional hydrotreater to convert the sulfur into hydrogen sulfide (H S). Because the portion of gasoline being hydrotreated is reduced in volume and free of olefins, hydrogen consumption and operating costs are greatly reduced. 

There are several ways to reduce acid consumption (and hence acid costs) significantly. These costs frequently account for about one-third of total operating costs of an alkylation unit using sulfuric acid as the catalyst. First, the refinery s choice of the feed acid has a fairly large effect on acid consumption. As a comparison, feed acids of between 98% and 99.5% acidity values will be considered, and the acids will be reduced to acidity values of 90%. In the first case, the acidity is decreased by 8% but for the second acid by 9.5%. Assuming that the acidity decreases per pass in the reactor are equal, then approximately 18-19% more alkylate are produced with the more concentrated feed acid. Several refineries currently use 99.5% feed acids, but others employ 98.5% feed acids. 

Generally, Claus plants are not considered for very small amounts of sulfur (less than 10-20 t/d) because the unit cost is extremely high at these small sizes. For this size range, processes normally considered for tail-gas treating become economically practical for the entire sulfur recovery operation. 

The UCBSRP process is claimed to have significantly lower capital and operating costs than the combination of an ethanolamine absorber/stripper unit plus a Claus plant plus a SCOT tail gas unit. Most of the energy consumed by the process is connected with the recovery and fractionation of propane and heavier hydrocarbons. Approximately 92% of the electrical power usage and 89% of the cooling requirements are associated with hydrocarbon recovery and separation (Sciamanna et al., 1988). The heat generated by the sulfur furnace more than offsets the heat demand required by the desulfurization of the natural gas stream. 

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