NFDC scientists are taking a new look at an old technique—applying phosphate rock directly to the soil. Direct application is especially attractive in some developing countries, TVA says, because it eliminates chemical processing and thus offers a means for rapidly bringing local phosphate deposits into use. To be agronomically effective, phosphate rock must be very finely pulverized. The dry product is very dusty and difficult to apply. TVA studies—partly funded by the International Fertilizer Development Center—suggest that one promising method for easier application of pulverized rock is to suspend the rock in water and then apply the suspension to the soil with ordinary spray equipment. This approach also would make it easier to include other plant nutrients, micronutrients, and possibly herbicides in one application. Best results to date have been obtained with rock-water-clay suspensions to which were added tetrasodium pyrophosphate as a dispersant and ammonium nitrate as a gelling agent. Suspensions with 60% rock content exhibited reasonably good storage properties, with little change in viscosity after aging. Although some clear liquid formed on top of the suspension, the settled portion remained soft and was remixed easily. The current work has been limited to laboratory-scale studies. Larger-scale tests are planned.
Also still in NFDC's chemical engineering laboratory is another process for making partially purified, polyphosphate-containing fertilizer solutions from impure wet-process acid. Starting material is urea phosphate, which can be made in relatively pure crystalline form by reacting urea with merchant-grade phosphoric acid. About 80% of the P2O5 is recovered as crystals containing only about 15% of the iron, aluminum, and magnesium impurities present in the feed acid. At temperatures above 250° F, urea acts as a condensing agent that converts orthophosphates to polyphosphates. In the method under development, the urea phosphate is heated in a pyrolysis reactor for 10 minutes at 275°, allowing a fluidstate condensation that forms a polyphosphate melt. Typically, about 50% of the orthophosphate is converted to polyphosphate, principally pyrophosphate. The urea ammonium phosphate melt is converted to a 15-28-0 liquid by reacting it with aqua ammonia. The heat input to the pyrolysis reactor is small—on the order of 8000 Btu per ton of urea phosphate, or 18,000 Btu per ton of P2O5. In comparison, TVA notes, more than 2 million Btu per ton of P 2 0 5 would be required to convert merchant-grade phosphoric acid to low-conversion superphosphoric acid suitable for feed to a pipe reactor for production of ammonium polyphosphate liquid fertilizers. D
Prospects for substitute fuels look poor Substitute fuels from coal and from oil shale, as well as coal itself, are the principal short-term alternatives to energy from oil and gas. But despite the more than 30 coal and shale conversion processes in some stage or other of development, progress toward a viable substitute-fuels industry hasn't kept pace with the optimistic predictions of the period following the oil embargo of 1973. The energy potential of coal and shale is considerable, but development has snagged on economic and legislative concerns, not to mention the unpredictability of pricing policies by the Organization of Petroleum Exporting Countries. The latest prognosis for coal and shale came last month from Christian W. Knudsen of the Energy Research & Development Administration, at present the most influential single organization affecting coal and shale development. Knudsen was speaking at the 11th Intersociety Energy Conversion Engineering Conference at Lake Tahoe, Nev. About 100 coal gasification, liquefaction, and shale-oil plants would be needed by the end of the century to hold oil imports to what is considered an acceptable level of roughly a third of domestic consumption. Each of the plants would have a capacity equivalent to 50,000 bbl of oil per day. The prospects for this total capacity are poor, even though an embryo energy plan has been offered by the Ford Administration. 36
C&EN Oct. 18, 1976
According to Knudsen, industry faces the prospect of $20-per-bbl oil and even higher priced substitute fuels, in contrast with the current world price of roughly 65% of this amount. The dilemma is that there are presently few incentives to launch a large synthetic fuels industry without some guarantees from govern-
ment. On the other hand, if, as most people expect, oil prices continue to rise, the future economic climate for such an industry would be more agreeable, possibly even without government guarantees. The heart of the dilemma, Knudsen says, is future inflation. Only if oil prices increase faster than the inflation rate will there be much of a case for development by private sources of a synthetic fuels industry in this country. The government response, so far, has been a $500 million per year coal conversion development program. ERDA also hopes to see Congressional approval of a $4 billion loan guarantee program to permit the construction of plants that can produce the equivalent of 350,000 bbl per day of oil by 1985. This would, ERDA believes, establish the necessary industrial base from which to expand thereafter in a more orderly way. But ERDA also believes that the loan guarantee program would be insufficient in itself. Also needed are price protection incentives. The loan guarantee program, if adopted by Congress, may yield coal conversion plants capable of producing 100,000, or even 200,000 bbl per day by 1985, well below previously projected capacity of 1 million bbl per day. The need, Knudsen says, is for additional legislation that will provide price protection on top of the loan guarantees. Otherwise, he says, the synthetic fuels program never will approach its desired potential, let alone recover any lost ground. Although the Lurgi converter still is considered the most likely device to usher in the first generation of substitute fuels, the lag in development may permit some of the many competitors to challenge the Lurgi converter. Two of the numerous processes mentioned at the conference were the Exxon catalytic gasification process and Arthur D. Little Inc.'s extractive coking process. Exxon's process is still in the early stages of development
Oil shale occurs in these areas in the U.S.
Western oil shale Eastern oil shale.
Oil shale areas
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C&ENOct. 18, 1976
but, Exxon says, it has shown distinct advantages over some of the other thermal conversion schemes. One of them is the elimination of problems due to caking of the coal feed, something that has plagued development of many processes to date. Exxon also believes that its process will require lower investment costs, partly through elimination of the requirement for coal pretreatment, and partly because of the elimination of shift conversion, methanation, and oxygen production. The Arthur D. Little process (C&EN, July 5, page 30) is being developed to produce liquid fuels. According to ADL, one attractive feature of its process is the ability to separate product liquids from unreacted coal and ash. This process is being tested in cooperation with ERDA's Pittsburgh energy research center. If the coal development picture is somewhat bleak, the oil shale picture is even less encouraging, and for about the same reasons. A delegation from the Institute of Gas Technology (IGT) has estimated proved and currently recoverable U.S. oil shale reserves at about 74 billion bbl. This estimate is based only on the most accessible shales in the Green River and Piceance basins of Colorado and Utah. The estimate also assumes shale yielding 30 gal per ton and a 60% recovery. If the yield down to 15 gal per ton is included, possible reserves jump to about 1.03 trillion bbl. In addition to the frequently reported shale oil recovery process, IGT has disclosed a new one. The IGT process yields synthetic natural gas and middle distillate oils. The process involves countercurrent heating of the shale in the presence of hydrogen at moderate pressures. This permits almost complete recovery of the organic values in the kerogen, compared with a maximum of about 75% recovery in most processes. Organic recoveries as high as 98% have been achieved in tests, but a typical recovery is 95%. Development work on this process is sponsored by the American Gas Association. Although shale oil development is reputed to be ready for commercialization, price competition from imported oil has placed that development in limbo. Paul Wellman of Ashland Oil notes that after all the problems are summed up, capital cost for a shale oil complex probably would approach the astronomical amount of about $1 billion, assuming a production capacity of 50,000 bbl per day. This is, says Wellman, almost twice the book value of Ashland Oil itself. Unless the price of oil exceeds $21 per bbl, there seems little likelihood that much more can be done to advance the cause of shale oil. Continued inflation will cast even more gloom on the prospects. Wellman says that without government support, any future shale oil industry probably will never get off the ground. Compounding the problems of inflation and price competition are the unsettled political and social climates in the U.S. Some oil industry executives have maintained that a consistent energy policy
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Sulfur nuggets have low-dusting properties Sulfur flows into a ship's hold (left) —without accompanying dust clouds. Clean handling, says Liquid Terminals Inc., Corpus Christi, Tex., is one advantage of what the company calls sulfur nuggets to distinguish them from other existing commercial forms such as slate, lump, and prills. The nuggets are produced by spraying molten sulfur into a water bath through proprietary spray nozzles developed by Liquid Terminals. The nuggets, the company says, compare well in low-dusting properties during handling, especially compared to slate sulfur, and exhibit a higher angle of repose in storage piles than do other dry forms. Equipment for processing sulfur to nuggets is less than $100,000 for a standard 85 tonper-hour operation. The system will be marketed jointly by Liquid Terminals, International Commodities Export Co., New York City, and Chemical Enterprises International Inc., Houston.
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C&EN Oct. 18, 1976
from Washington would dispel some of the uncertainty, but that policy has not manifested itself yet. Similarly, the threat of divestiture has not encouraged prospective investors. In shale oil development work completed to date, every effort has been made to comply with existing environmental regulations, and there is no doubt that a commercial plant would be in compliance with all regulations. However, oil industry executives also have voiced the opinion that if changes to the Clean Air Act presently under consideration become law, they would preclude the further development of a shale oil industry. This prospect has, apparently, been noted in Congress, where the new Clean Air Act is in a state of indefinite suspension. At the same time, this element introduces another uncertainty that makes planning difficult, to say the least. The gloom in oil shale development is not total, however. Although western shale deposits receive almost exclusive attention, there are other shale resources that are creeping into the consciousness of developers. These deposits, although lower in quality, are more extensive. In general they run in a wide belt, roughly from southwestern Texas through northwestern New York. Dow Chemical has been involved with the shale deposits that underlie lower Michigan for about 20 years, but only since the early 1970's has this involvement been emphasized. According to Dow's Dr. John H. Humphrey, the company's present interest is centered on in situ combustion of the shale in a zone fractured with conventional explosives. In the Midwest and eastern U.S., about 400,000 square miles are underlain with a Devonian shale called by many names but known at Dow as Antrim shale. This type of shale is substantially different from western shale, both in origin and in composition. Eastern shale is mainly illite, a mineral containing iron, aluminum, potassium, magnesium, and silicon, and very little carbonate. This composition is quite important, Humphrey says, because shales with high carbonate content are correspondingly highly endothermic when processed, thereby requiring high heat inputs. Eastern shale does not suffer this handicap. However, the scales are somewhat balanced by the lower quality of eastern shale. Western shales typically yield up to 25 gal per ton and more. Eastern shales yield only about half that amount. Eastern shales also yield more gas than western shales, as much as 1000 cu ft per ton. Dow's present development work is directed at in situ retorting in the Thumb region of lower Michigan, near Dow headquarters. Here the Antrim shales are from 1220 to 1440 feet below ground. During one test, the gaseous hydrocarbon yield was "quite high," with a heating value of 477 Btu per scf. Other tests have been inconclusive but the prospects have been encouraging enough to generate additional development funding from ERDA. •
