crease a utility's megawatt output, and to avert a threatened environmental shutdown of ingot production at a metal casting plant. We have also solved some serious problems in plant design and regulatory compliance." G
New scrubbers tackle S0 2 emissions problem Whatever else may be said of utilities' switching to coal from oil and gas, there is still only moderate enthusiasm over the ways and means of controlling sulfur dioxide emissions from boilers and other combustors. Scrubbers currently are the most popular way, but by legislation and economics they seemingly have been all but forced into a service for which they may not be at all suited. The status of development and commercialization of stack gas scrubbers was outlined at the Coal Technology '78 meeting by Robert E. Moser, a representative of Brown & Root's Houston office. The original scrubbing systems were based on calcium hydroxide/calcium carbonate slurries to absorb the sulfur dioxide. Reaction in the slurries yields calcium sulfate precipitate. The precipitate is difficult to handle, causes maintenance problems because of the tendency to plug lines and fittings, and the sludge is difficult to dispose of. Some sodiumbased processes have been developed in the laboratory that show potential. Magnesium oxide wet systems and some other dry systems also are under investigation, but the present technology is dominated by the calcium systems. About 90% of all the systems in place are based on calcium absorbents. At least 10 vendors offer systems. As difficult as they may be to operate, the slurry systems are generally regarded as the best proven technology. There are, however, some newer ideas in development. In West Germany, the Saarberg-Holter process is essentially an active lime process with the addition of hydrochloric acid to the slaked lime. This is supposed to produce a clear alkaline calcium chloride solution as the scrubbing medium. Calcium bisulfite is produced in
the absorber and is oxidized to produce gypsum. The major advantage is the clear solution rather than the slurry. Most of the erosion experienced in slurry systems is eliminated and there is said to be little or no routine plugging of the system. The disadvantage is the acid medium which promotes corrosion. The developers claim that they have a proprietary "catalyst" that counteracts acidic corrosion. Still in the development stage is an ammonia scrubbing system that has been plagued by the "blue plume" carryover of ammonia salt vapor. A recent six-month trial indicates that the "blue plume" problem has been diminished but not eliminated. The sodium citrate process under development by the U.S. Bureau of Mines uses a mixed solution of sodium citrate, citric acid, and sodium thiosulfate in which to absorb the sulfur dioxide. In solution, the SO2 is then contacted with hydrogen sulfide to yield elemental sulfur and regenerated sodium citrate. This process has not been demonstrated on a large scale, Moser says, but it still is an attractive possibility. Another wet scrubbing process is based on potassium thiosulfate absorbent. The chemistry is very complex and it is not yet clear if it offers any important advantages over sodium scrubbing absorbents. At least three dry absorption systems are under development. Dry, activated carbon is being considered by at least two industrial consortia—Bergbau Forshung/Foster Wheeler and Catalytic/ Westvaco. The carbon absorbs the SO2, and converts it to sulfuric acid via oxidation. The laden absorbent is then transferred to another vessel where the SO2 is regenerated and eventually converted to elemental sulfur while the absorbent is recycled. Considerable solids-handling equipment is required for this process. Shell and UOP are jointly developing a closed-loop process based on fixed beds of cupric oxide supported on alumina. The SO2 reacts with the cupric oxide to yield cupric sulfate, which is subsequently reduced to yield sulfur and regenerated cupric oxide. The advantage is that much lower temperatures are possible than in the activated carbon processes. This process apparently has not been demonstrated on a large scale.
Power industry now use these gas scrubber process m.
" "~*- a i
4,047 4,237 00
-i*»_^ mmmmmmmmm mmmmmmmmm ι
•* · -
-' •- •
!·~"Γ·1 TOTAL «to*
24 C&EN Nov. 6, 1978
tao 118 0 0
>ém*****m + MTO 3,773 0 0 0 71§ «2 0 1M10
Twr 7,430
M*a 0 • §34 730 130 230 100
13,003 13,032 20 1,000 343
toto 1,102 100
Some investigations of dry nahcolite (a naturally occurring sodium bicarbonate mineral) absorbents have been made with mixed results. The nahcolite is injected into the gas stream, reacts with the SO2, and is removed downstream in a bag house. An alternative is coating the bags with nahcolite. In any case, the efficiency of the SO2 removal depends on either recycling a large amount of nahcolite and gas or using a great excess of nahcolite. Spent absorbent probably would present problems, if this particular process is ever used. D
Coal users look at shipping alternatives A decision by the Interstate Commerce Commission (ICC) to allow an increase in certain freight rates for transportation of coal has produced an agonized reaction from coal consumers. It also has provided advocates of regional coal stockpiles, slurry pipelines, and augmented water transportation of coal with ammunition to make a major assault on the railroads' entrenched position. At least its timing buttressed arguments for these alternatives advanced at the recent Coal Technology '78 meeting held in Houston just days before. As is the case with many bulk commodities, transportation often constitutes the largest part of the cost of coal to the consumer. The unit train, an entire trainload of coal delivered to a single site, represents the lowest-cost transportation. Slurry pipelines probably could lower that cost. However, one problem that looms increasingly large with pressures to switch from oil and gas to coal is that only consumers of very large amounts of coal can afford to buy in quantities great enough to justify unit trains or dedicated pipelines. Unit train rates may be as low as one sixth of conventional rates. Cooperatives are one solution; at least two major ones are being set up, both in the Galveston, Tex., area. One is being designed and developed by ORBA Corp. on Pelican Island. The other, managed by CAM Co., is a pending joint venture by Union Carbide, Amoco Texas Refining Co., Amoco Chemicals, and Monsanto. A final decision on the CAM plant is scheduled for early 1979. If the decision is to proceed, as is expected, construction will be completed and the first steam generated in 1984. The CAM plant would occupy a 114acre site and consist of a cogeneration plant to provide process steam for the parent companies and electricity to a local utility. To fuel the plant, coal and lignite would be stored on-site after transport by rail and barge. When on stream, the CAM plant would provide 4.6 million lb per hour of steam. The partners would take 3 million lb as process steam; the rest would provide 100 Mw of electricity to be distributed by Community Public Service Co. Cogen-
