411 FOSSIL FUEL CLEANING PROCESSES The amount of pollutants, especially sulfur oxides and par- ticulates emitted to the atmosphere may be reduced by treat- ing fuels prior to combustion. This approach may be more energy effi cient than treatment of fl ue gases as per Vapor and Gaseous Pollutant Fundamentals. More than thirty million tons of sulfur dioxide are discharged annually in the United States, 75% of which is the result of fuel burning. FOSSIL FUEL PRODUCTION, RESERVES AND CONSUMPTION The world’s production of oil in 1980 was 66 million barrels per day with a projected value of 77 MBPD for the year 2000. The relatively small anticipated increase refl ects increased con- servation and alternate fuel source application. The overall oil output of the USSR was about 14 MBPD 1 as compared to about 12 MBPD for combined US and Canadian production (1980). About 2500 trillion cubic feet of natural gas reserves are estimated to exist worldwide. The US reserves are 200 TCF with an annual consumption of about 20 TCF. Soviet bloc production was about 15 TCF in 1980. Most oil and natural gas reserves fall in a crescent shaped area extending from Northern Algeria Northward to West Siberia. Lynch 2 felt that the level of surplus capacity would remain stable for the early ’90s with the then world stock level of about 100 gigaliters (1.3 giga barrels). Coal is consumed at a rate of 600 million tons annually in the US utility industry. Only a small portion of Eastern US coals fall in the low (less than 1% sulfur) category—see Table 1. The US, USSR and China own about two thirds of the world’s 780 billion tons of presently recoverable coal reserves. The US has about one quarter of the total. Coal accounts for 90% of the US’s proven reserves. 3 Consumption of fuel might be measured in “quads” or quadrillion Btu’s. It has been estimated that US electric con- sumption was 13 quads and nonelectric industrial about 16 quads for the year 1980. 3 Total US fossil fuel consumption is about 76 quads, most in the non-industrial sector. Worldwide energy consumption is predicted to double over the next 25 years according to the World Energy Council. 3a The pre- dicted fossil fuel usage in terms of billions kwh electric gen- eration in the year 2015 is for coal-2000, natural gas-1000, nuclear-400, and petroleum-less than 100. Renewables are estimated at 400 billion kwhs. Divide these numbers by 100 to estimate the number of quads; assuming a plant effi ciency of current Rankine cycle plants (about 34%) or by 170 if a combined cycle (Brayton ϭ Rankine) is assumed. SULFUR REMOVAL Typical legislative actions have been the setting of limits on the allowable sulfur content of the fossil fuel being burned or on the SO 2 emission rates of new sources. In California, regula- tions have limited the use of fuel oil to those of 0.5% or less sulfur. Since 1968, a limit of a 0.3% sulfur oil has been in effect in New York City. In 1980, Massachusetts set a 1% sulfur limit on the coal to be burned. This limit is being considered for other Atlantic seaboard states as coal conversion is increasingly encouraged. Chemical and physical desulfurization of fossil fuels can be used to produce levels of sulfur which comply with government standards. To reduce a 3% sulfur coal to a 1% sulfur coal may add about 10% to the cost of coal F.O.B., but may save on transportation and fl ue gas desulfurization costs. The amount of sulfur dioxide emitted worldwide might double in the next decade due to increased energy demands (approximately 3.5% annually) and the use of more remote crudes having higher sulfur concentration. The chemical and power industries must strike a delicate balance between the public’s dual requirement of increased quantities and preparation of fossil fuel. More fuel must now be desulfurized more completely and/or more sulfur diox- ide must be removed from stack gases. The techniques for cleaning fossil fuels used throughout the petroleum, natural gas and coal production industries are covered in this arti- cle. Treatment of stack gases to effect particulate and sulfur removal are discussed separately in other articles. PROCESSES INVOLVING THE BASIC FUELS The two most commonly combusted energy sources are coal and fuel oil having typical sulfur ranges of 1–4% and 3–4%, respectively; a 3% sulfur oil produces about the same SO 2 emission as a 2% sulfur coal when based on a comparable energy release. Fuel oil desulfurization is used by most major oil producers. Hydrogenation, solvent extraction, absorption and chemical reaction are used to varying extents at petro- leum refi ners. Finfer 4 claims a possible sulfur reduction from 2.5 to 0.5% by a hydrodesulfurization process. Coal contains sulfur which may be combined with either the organic or © 2006 by Taylor & Francis Group, LLC 412 FOSSIL FUEL CLEANING PROCESSES inorganic (pyritic and sulfate) matter. The organics may be removed by various cleaning processes, but little reduction in organic sulfur has been found to occur by physical clean- ing methods. Currently an extraction process, followed by hydrogenation, is being tried. Some coals have been reduced to S contents below 2%, and typical sulfur reduction esti- mates are in the range of 20–40% reduction. 5,6,7 Even if these reduced levels are achieved, a need for further removal of sulfur from the fl ue gases might exist. Cleaning, when com- bined with fl ue gas desulfurization as a method of SO 2 con- trol, could eliminate the need for reheat and considerably reduce the sludge handling requirements of the plant. Fuel Oil Desulfurization (General) Before the ecological need for fuel oil desulfurization was recognized, oil stocks were desulfurized for a number of other reasons: 1) To avoid poisoning and deactivation of platinum cat- alysts used in most catalytic reforming processes. 2) To reduce sulfurous acid corrosion of home burner heating equipment. 3) To demetalize crude stocks (sulfur removal from crude is generally accompanied by a concomitant removal of such trace metals as sodium, vanadium and nickel). 4) To recover pure sulfur. 5) To reduce or eliminate final product odor. By defi nition, hydrodesulfurization is the removal of sulfur by a catalytic reaction with hydrogen to form hydrogen sulfi de. As carried out in the petroleum industry, the hydrode- sulfurization process is not a specifi c chemical reaction. Various types of sulfur compounds (mercaptans, sulfi des, polysulfi des, thiophenes) with varying structures and molecu- lar weights are treated. Obviously, they react at various rates. TABLE 1 Ash content and ash fusion temperatures of some U.S. coals and lignite Rank Low Volatile Bituminous High Volatile Bituminous Subbituminous Lignite Seam Pocahontals No. 3 No. 9 Pittsburgh No. 6 Location West Virginia Ohio West Virginia Illinois Utah Wyoming Texas Ash, dry basis, % 12.3 14.10 10.87 17.36 6.6 6.6 12.8 Sulfur, dry basis, % 0.7 3.30 3.53 4.17 0.5 1.0 1.1 Analysis of ash, % by wt ——————— SiO 2 60.0 47.27 37.64 47.52 48.0 24.0 41.8 Al 2 O 3 30.0 22.96 20.11 17.87 11.5 20.0 13.6 TiO 2 1.6 1.00 0.81 0.78 0.6 0.7 1.5 Fe 2 O 3 4.0 22.81 29.28 20.13 7.0 11.0 6.6 CaO 0.6 1.30 4.25 5.75 25.0 26.0 17.6 MgO 0.6 0.85 1.25 1.02 4.0 4.0 2.5 Na 2 O 0.5 0.28 0.80 0.36 1.2 0.2 0.6 K 2 O 1.5 1.97 1.60 1.77 0.2 0.5 0.1 Total 98.8 98.44 95.74 95.20 97.5 86.4 84.3 Ash fusibility — — — — — — — Initial deformation temperature, F Reducing 200+ 2030 2020 2000 2060 1990 1975 Oxidizing 2900+ 2420 2265 2300 2120 2190 2070 Softening temperature, F Reducing 2450 2175 2160 2180 2130 Oxidizing 2605 2385 2430 2220 2190 Hemispherical temperature, F Reducing 2480 2225 2180 2140 2250 2150 Oxidizing 2620 2450 2450 2220 2340 2210 Fluid temperature, F Reducing 2620 2370 2320 2250 2290 2240 Oxidizing 2670 2540 2610 2460 2300 2290 © 2006 by Taylor & Francis Group, LLC FOSSIL FUEL CLEANING PROCESSES 413 In addition, during the course of desulfurization, non-sulfur containing molecules may be hydrogenated and in some cases cracked. The fl ow design of hydrosulfurization process systems is relatively simple. Preheated oil and hydrogen under pres- sure are contacted with catalyst. The effl uent from the reac- tor is passed to one or more separators to remove most of the effl uent hydrogen and light hydrocarbon gases produced in the operation. These gases are generally recycles with or without prior removal of light hydrocarbons by absorption. The separa- tor liquids may be stripped, rerun or otherwise treated to obtain hydrogen sulfi de free products of the desired boiling range. Except in the case of residuum processing, plant design options are few in number and relatively simple. For exam- ple, in the processing of distillates, correlation systems have been developed which relate degree of desulfurization to about three parameters which defi ne the charge stock, reac- tor temperature, temperature, pressure, feed space velocity, hydrogen rate and a catalyst activity parameter. When residuum stocks are considered, however, general- izations are not so easily made. The wide variance in resid- uum properties (i.e., atmospheric or vacuum type, viscosity, Conradson carbon content, metal content and the paraffi nic or aromatic nature of residuum) makes each case a special one as far as process design. Catalyst poisoning due to metals deposition on the catalyst surface can reduce overall desulfur- ization yields. Catalyst must then be regenerated or replaced, thus adding to overall cost of the particular system employed. An alternative to desulfurization exists, that being the use of natural low sulfur fuel oils. They may be used alone or in blends with higher sulfur content material. The major source of low sulfur fuel oil is North African crudes, princi- pally from Libya and Nigeria, and some Far Eastern crude from Sumatra. Fuels made from these crudes will meet even very low sulfur regulations calling for 0.5% sulfur or less. However, the highly waxy nature of these paraffi nic materi- als makes handling diffi cult and costly. Therefore, the blend becomes a more palatable course of action. Blends of natural low-sulfur fuels oils with other high sulfur fuel oils will be adequate in some cases to meet more moderate sulfur regulations. The fuel oil fractions of North African crudes contain about 0.3% S. Thus signifi - cant amounts of higher sulfur fuel oils can be added to make blends calling for 1–2% sulfur. These blends have physical properties which obviate the need for specialized handling (a must for existing industrial installations). Before delving into specifi c desulfurization technology and applications, pertinent terms will be defi ned. Figure 1 FUEL OIL NAPHTHALE N NO. 6 FUEL OIL BENZENE TOLUENE H G I F E L ATM GAS OIL H 2 KEROSENE PREMIUM GASOLINE RES. GASOLINE BUTANE NAT GASO D C NAPHTHA A B CRUDE LIGHT ENDS LIGHT REFORMATE HEAVY REFORMATE GENERAL FLOWSHEET - CRUDE OIL PROCESSING LEGEND A - CRUDE DISTILLATION B - CATALYTIC REFORMER C - BTX EXTRACTION D - GASOLINE POOL E - PYROLYSIS F G H I - HYDRODEALKYLATION HYDROTREATER TAR ALKYL NAPHTHALENE FIGURE 1 © 2006 by Taylor & Francis Group, LLC 414 FOSSIL FUEL CLEANING PROCESSES schematically represents a general fl owsheet for crude oil pro- cessing. Crude oil, as received from the source is fi rst atmo- spherically distilled. Light ends and mid-distillates from this operation are further processed to yield gasolines and kero- sene. Atmospheric residuum can be directly used for No. 6 fuel oil, or further fractionated ( in vacuo ) to produce vacuum gas oil (vacuum distillate) and vacuum residuum. After atmo- spheric distillation, the average crude contains about 50% of atmospheric tower bottoms, which is nominally a 650ЊF ϩ oil. The vacuum distillation yields roughly equal parts of vacuum gas oil and vacuum residuum. The bottoms from this unit is nominally a 975ЊF ϩ oil, although the exact cut point will vary for each vacuum unit. Desulfurization of vacuum residuum would be appli- cable where a refi nery has use for the virgin vacuum gas oil other than fuel oil, and sulfur restrictions or increased prices make desulfurization of vacuum bottoms attractive. Another situation is where desulfurizing the vacuum gas oil and blending back with vacuum bottoms no longer produces a fi nal fuel oil meeting the current sulfur specifi cation. Present in the residuum (vacuum) is a fraction known as asphaltenes. This portion is characterized by a molecu- lar weight of several thousand. The majority of the organo- metallic compounds are concentrated in the asphaltene fraction. Although many of the metals in the periodic table are found in trace quantities, vanadium and nickel are usu- ally present in by far the highest amounts. Residual oils from various crudes differ from each other considerably in regard to hydrodesulfurization. These differences reside to a great extent in the asphaltene fraction. Light Oil Desulfurization The G O-Fining Process The G O-Fining process is designed for relatively complete desulfurization of vacuum gas oils, thermal and catalytic cycle oils, and coker gas oil. It represents an extremely attractive alternative where a lesser degree of sulfur removal from the fuel oil pool and/or a very low sulfur blending stock is required. The feed to the G O-Finer System is atmospheric residuum. This stream is vacuum fractionated and the resulting vacuum gas oil (VGO) is desulfurized using a fi xed bed reactor system. Resultant VGO is then reblended with vacuum bottoms to yield a desulfurized fuel oil or used directly for other applications. Figure 2 shows quantitative breakdown of various process streams for a 50,000 barrel per stream day (BPSD) operation utilizing a 3% sulfur Middle East atmospheric residuum feed. The process has the capa- bility of producing 49,700 BPSD of 1.72% S fuel oil. There are currently a number of G O-Fining units in commercial operation. Investment and operating costs will vary depending on plant location and crude stock characteristics, but for many typical feedstocks (basis 50,000 BPSD) total investment is about 16.3 million dollars and operating costs average out at 60¢/barrel fuel oil (1989). UOP ’ s gas desulfurization process Another light oil desul- furization process is UOP’s gas oil desulfurization scheme. Unlike the previously discussed G O-Fining process, UOP’s scheme (already commercial) is designed for almost complete (ϳ90%) desulfurization of a 630 to 1050; F blend of light and vacuum gas oils (approximate sulfur content of feed—1.5%). Vacuum residuum is neither directly nor indirectly involved anywhere in the process. In almost all other respects, however, UOP’s process parallels G O-Fining. The current plant facility is of 30,000 BPSD capacity with above mentioned feed. Comparison of UOP and G O-Finer costs show that both are of the same order of magnitude and differ markedly only in initial capital investment. This is in part attributable to the fact that a G O-Fining facility requires atmospheric resid- uum fractionation whereas UOP’s does not. Stocks of high-sulfur content are diffi cult to crack cata- lytically because all or most of the catalysts now in com- mercial use are poisoned by sulfur compounds. In recent years the trend has been toward processes that remove these sulfur compounds more or less completely. The high sulfur 1100°F Vacuum Bottoms 16,600 BPSD 4.2 wt % s A B 700–1100°F VGO 33,400 BPSD 2.33 WT % S MIDDLE EAST 700°F + RESID 50,000 BPSD 3.0 WT % S 33,100 BPSD 0.3 WT % S 400°F + Desulfurized Fuel Oil 1.72 WT % s THE GO–FINING PROCESS FIGURE 2 © 2006 by Taylor & Francis Group, LLC FOSSIL FUEL CLEANING PROCESSES 415 contents of petroleum stocks are mainly in the form of thio- phenes and thiophanes and these can be removed only by catalytic decomposition in the presence of hydrogen. The Union Oil Company has developed a cobalt molybdate desulfurization catalyst capable of handling the full range of petroleum stocks encountered in refi ning operations. Even the more refractory sulfur compounds associated with these stocks are removed. This catalyst exhibited excellent abra- sion resistance and heat stability, retaining its activity and strength after calcination in air at temperature as high as 1470ЊF. 8 Cobalt molybdate may be considered a chemical union of cobalt oxide and molybdic oxide, CoO · MoO 3 . The high activity of this compound is due to an actual chemical combination of these oxides with a resultant alteration of the spacing of the various atoms in the crystal lattice. 8 Catalyst life is two to fi ve years. Catalyst poisons consisted of carbon, sulfur nitrogen and polymers. Regeneration is accomplished at 700 to 1200ЊF using air with steam or fl ue gases. The fundamental reactions in desulfurization are as follows: General Reaction C n H m S p ϩ x H 2 → C n H mϩ 2xϪ 2p ϩ p H 2 S Desulfurization of ethyl mercaptan C 2 H 5 SHϩ H 2 → C 2 H 6 ϩ H 2 S ∆ HϭϪ19.56 kg cal/mole Desulfurization of diethyl sulfi de (C 2 H 5 ) 2 Sϩ 2H 2 → 2C 2 H 6 ϩ H 2 S ∆ HϭϪ36.54 kg cal/mole Desulfurization of thiophene C 4 H 4 Sϩ 4H 2 →C 4 H 10 ϩ H 2 S ∆ HϭϪ73.26 kg cal/mole Desulfurization of amylene C 5 H 10 ϩ H 2 →C 5 H 12 ∆ Hϭ −33.48 kg cal/mole. The change in heat content for all these reactions is negative, indicating that they take place with evolution of heat. The sulfur content in Middle East Gas Oil, a typical feed, is 1.25% by weight. The pilot plant data shows that the heat effect is not serious and whole process can be treated as isothermal. The chemical reaction process on the catalyst is postu- lated to proceed on the surface of the catalyst by interaction of the sulfur-bearing molecules and hydrogen atoms formed through activated absorption of hydrogen molecules. 9 Oil molecules are more strongly absorbed than hydrogen mol- ecules, and therefore may preferentially cover part of the surface, leaving less surface available for dissociation of hydrogen molecules. In the presence of diluent, namely, N 2 , it can also compete for free sites on the surface, and accord- ingly may cause a reduction in the concentration of hydro- gen on the surface, thus giving the lower rate constant when working with H 2 −N 2 mixture. Conversion of the sulfur compounds to hydrogen sulfi de and saturated hydrocarbons occurs by cleavage of the sulfur to carbon bonds; essentially no C—C bonds are broken. Residuum Desulfurization The H-Oil-process ( Cities Service ) In order to meet the need for an effi cient method of desulfurizing residual oils with- out the complexities encountered in the myriad of existing fi xed bed catalytic systems, Cities Service developed what is known as the H-Oil system. Although fi xed bed catalytic reactors had been extensively used for desulfurizing distillate oils, desulfurization of residual oil in a fi xed bed reactor presented several diffi culties: 1) the high temperature rise through the bed tended to cause hot spots and coking, 2) the presence of solids in the feed and the forma- tion of tar-like coke deposits on the catalyst tended to cause a gradual build-up of pressure drop over they catalyst bed and 3) because of the relatively rapid deactivation of the catalysts, system shut down for catalyst replacement occurred often, on the order of six times yearly. To overcome these problems an ebbulated bed reactor was designed. Figure 3 is a simplifi ed drawing of reactor workings. The feed oil is mixed with the recycle and makeup hydrogen gas and enters the bottom of the reactor. It passes up through the distributor plate which distributes the oil and gas evenly across the reactor. The reaction zone consists of a liquid phase with gas bubbling through and with the catalyst particles suspended in the liquid, and in random motion. It is a back-mixed, iso- thermal reactor, with a temperature gradient between any two points in the reactor no greater than 5ЊF. Due to the catalyst suspension in liquid phase, cata- lyst particles do not tend to adhere to one another, causing blockage of fl ow. Any solids present in the feed pass directly through the reactor. Reactor pressure drop is constant. One of the more important aspects of the ebbulated bed reactor system is that periodic shutdowns for catalyst replacement is not necessary. Daily catalyst replacement results in a steady state activity. Table 2 shows examples of H-Oil desulfurization perfor- mance with atmospheric and vacuum residuals. In addition, investment and operating cost data are shown to illustrate the important effect of feed stock characteristics on overall economics. Cases 1–3 describe processing of three atmospheric resid- ual feeds. The Kuwait Residuum treated in case 1 is a high sulfur oil containing relatively low metals content (60 PPM). Therefore, the rate of catalyst deactivation is low and operat- ing conditions are set to minimize hydrocracking and maxi- mize desulfurization. In fact, only 2–3% naphtha and 9–10% middle distillate are produced. The actual chemical hydrogen consumption is fairly close to the estimated needed to remove the sulfur. For many atmospheric residuals which are not too high in metals, this case is typical to give maximum production of low sulfur fuel oil at minimum conversion and hydrogen consumption. © 2006 by Taylor & Francis Group, LLC 416 FOSSIL FUEL CLEANING PROCESSES In case 2, although metals content is also low (ϳ40 PPM), hydrogen consumption is exceptionally high. This is due to the fact that conversion was not minimized and 7% naphtha and 13% middle-distillate was produced by hydrocracking. Case 3 is characteristic of high metals content (ϳ320 PPM) oils from that area. As noted previously, catalyst deactivation increases with metals content. Therefore, catalyst addition rates are higher, resulting in increased operating costs. To compensate for the reduced catalyst activity, higher operating temperatures and/or residence times are used. Cases 4–6 summarize vacuum residua operations. Desulfurization rates for vacuum residua are lower than for atmospheric. The asphaltenes and metallic compounds reside in the vacuum residuum, consequently increasing catalyst deactivation rates and therefore catalyst costs per barrel. In all the cases depicted (4–6) hydrogen consumption, relative FRESH CATALYST REACTOR II REACTOR I FEED OIL MAKE-UP HYDROGEN RECYCLE HYDROGEN THE H-OIL PROCESS LIQUID PRODUCT FIGURE 3 TABLE 2 H-OIL desulfurisation of atmospheric and vacuum residuals Type-Feed (A-atmos) (V-vacuum) Case 1A Case 2A Case 3A Case 4V Case 5V Case 6V Source Kuwait W. Texas Venezuela Kuwait W. Texas Venezuela Feedstock data —— — —— — Sulfur (Wt%) 3.8 2.5 2.2 5.0 2.2 2.9 Vanadium and nickel (PPM) 60 40 320 90 55 690 975ºFϩ —— — —— — Vol% 45 45 52 80 70 75 Sulfur, Wt% 5.3 3.2 2.8 5.3 2.7 3.2 Yield, quality (400ºFϩ) —— — —— — Vol% 99.3 96.0 94.2 94.7 92.9 92.9 % S 0.9 0.4 0.9 1.8 0.6 1.2 Chemical H 2 —— — —— — Consumption (SCI-/BBL) For S removal (est.) 290 210 140 340 170 200 Total 490 670 470 660 640 920 Economics (Relatives) —— — —— — Capital inv. est. 6.7 7.8 6.9 7.9 8.3 8.9 OP cost, (20,000 BPSD UNIT) 33 40 39 44 46 65 © 2006 by Taylor & Francis Group, LLC FOSSIL FUEL CLEANING PROCESSES 417 SEPARATOR FLASH DRUM LOW SULFUR FUEL OIL MID- DISTILLATE GASOLINE HYDROGENREDUCED CRUDE FEED REACTOR GASES RCD ISOMAX FIGURE 4 WHOLE CRUDE (117, 000 BPSD) TWO STAGE DESALTER (50,000 BPSD) REACTOR 650°F+ ATMOSPHERIC CRUDE DISTILLATION HYDROGEN FRACTIONATOR C 4 0.1% SULFUR MID DISTILLATE 1% SULFUR FUEL OIL (40,000 BPSD) TO SULFUR RECOVERY 350°F - (30,300 BPSD) 350–650°F - (36,400 BPSD) RDS ISOMAX FIGURE 5 © 2006 by Taylor & Francis Group, LLC 418 FOSSIL FUEL CLEANING PROCESSES WHOLE CRUDE (100,000 BPSD) TWO STAGE DESALTER CDS ISOMAX REACTOR HYDROGEN CDS ISOMAX SYNTHETIC CRUDE FRACTIONATOR 0.1% SULFUR MIDDLE DISTILLATE (29,600 BPSD) 1% SULFUR FUEL OIL (40,000 BPSD) C 5 C 4 FIGURE 6 REACTORS FEED FURNACE RECYCLE HYDROGEN ABSORBER HIGH PRESSURE LOW PRESSURE SEPARATORS TO GAS RECOVERY LIGHT GASOLINE HEAVY NAPHTHA LIGHT GAS OIL 650°F+ BOTTOMS (1% S) HDS H 2 FIGURE 7 © 2006 by Taylor & Francis Group, LLC FOSSIL FUEL CLEANING PROCESSES 419 to that needed for desulfurization, is high indicating that high sulfur content of feed precludes setting of operating condi- tions to minimize conversion. In fact, naphtha production ranges from 7–15%, mid-distillates from 15–23%. The Isomax processes A broad spectrum of fi xed bed desulfurization and hydrocracking processes are now in oper- ation throughout the world. They are characterized by their ability to effectively handle a wide range of crude feedstocks. In addition, some of the processes are capable of directly desul- furizing crude oil while others treat only residual stocks. Rather than discuss each process individually, a compar- ative summary of the major ones is presented in Table 3. There are many other processes which in one way or another effect a reduction in the amount of sulfur burned in our homes and businesses. All of them use some type of proprietary catalytic system, each with its own peculiar optimum operating ranges with regard to feed composition and/or reactor conditions. The hydrodesulfurization process is still relatively expensive (in 1989 more than 75¢/BBL) by petroleum pro- cessing standards. The capital investment for large reactors which operate at high pressures and high temperatures, the consumption of hydrogen during the processing and the use of large volumes of catalyst with a relatively short life all contribute to the costs. In addition, processing costs also depend on the feedstock characteristics. But when one considers the awesome annual alternative of 30 million tons of sulfur dioxide being pumped into the atmosphere, the cost seems trifl ing indeed. Desulfurization of Natural Gas Approximately 33% of the natural gas in the United States and over 90% of that processed in Canada is treated to remove normally occurring hydrogen sulfi de. The recovered sulfur, which now accounts for about 25% of the free world’s production is expected to increase in the future. Current processes may be classifi ed into four major categories: 1) Dry Bed—Catalytic Conversion, 2) Dry Bed—Absorption—Catalytic Conversion, 3) Liquid Media Absorption—Air Oxidation, 4) Liquid Media Absorption—Air Conversion. Dry bed catalytic conversion ( the Modifi ed Claus Process ) The Modifi ed Claus Process is used to remove sulfur from acid gases which have been extracted from a main sour gas stream. The extraction is done with one of the conventional gas treating processes such as amine or hot potassium carbonate. The process may be used to remove sulfur from acid gas streams containing from 15 to 100 mole % H 2 S. The basic schemes use either the once through process or the split stream process. Figure 8 shows fl ow characteristics of the once-through scheme, which in general gives the high- est overall recovery and permits maximum heat recovery at a high temperature level. Split stream processes are generally employed where H 2 S content of the acid gas is relatively low (20–25 mole %) or when it contains relatively large amounts of hydrocarbons (2–5%). Pertinent design criteria for dry bed catalytic conversion plants include the following: 1) Composition of Acid Gas Feed, 2) Combustion of Acid Gas, 3) For a Once-Through Process, Retention Time, of Combustion Gases at Elevated Temperatures, 4) Catalytic Converter Feed Gas Temperature, 5) Optimum Reheat Schemes, 6) Space Velocity in the Converters, 7) Sulfur condensing Temperatures. TABLE 3 Process RCD Isomax RDS Isomax CDS ISomac HDS Licensers UOP Chevron Chevron Gulf R & D General feed type Atmospheric Atmospheric Whole crude Residuum Feed characteristics Name Kuwait Arabian light Arabian light — Sulfur content 3.9 3.1 1.7 5.5 Process diagram Figure 4 Figure 5 Figure 6 Figure 7 Fuel oil product Quantity (BPSD) 40,000 40,000 40,000 40,000 Sulfur content 1.0 1.0 1.0 2.2 Economies (Relative) Investment a 9.7 24.5 156.7 10.0 Operating costs b 51 40–60 40–60 — a Includes only cost for Isomax reactor/distillation and auxiliary equipment. b Includes utilities, labor, supervision, maintenance, taxes, insurance, catalyst, hydrogen, etc. © 2006 by Taylor & Francis Group, LLC 420 FOSSIL FUEL CLEANING PROCESSES ACID GAS AIR B+RC WHB 2nd HOT GAS BYPASS 1st HOT GAS BYPASS MODIFIED CLAUS PROCESS TAIL GAS LEGEND B+RC - BURNER + REACTION CHAMBER WHB - WASTE HEAT BOILER R - CATALYTIC CONVERTOR C - CONDENSER S L - LIQUID SULFUR S L S L S L R 1 R 2 C 1 C 2 FIGURE 8 SWEET GAS WASTE GAS LIQUID SULFU R AS AIR SOUR GAS LEGEND R - ZEOLITE BED ABSORBERS C 1 - SULFUR CONDENSER C 2 - ARIAL COOLER AS - ACCUMULATOR/SEPARATOR B - SULFUR BURNER R 1 R 2 C 2 C 1 B HAINES PROCESS FIGURE 9 © 2006 by Taylor & Francis Group, LLC [...].. .FOSSIL FUEL CLEANING PROCESSES 421 LIQUID MEDIA ABSORPTION SWEET GAS SK SULFUR FROTH LEAN SOLUTION R A F SULFUR CAKE FILTRATE SOUR GAS AIR RICH SOLUTION LEGEND A - ABSORBER R - REGENERATOR SK - SKIM TANK F - FILTER FIGURE 10 The sulfur from a claus plant may be produced in various forms, such as liquid, flaked or prilled Form of choice is determined by transportation mode and end usage... traceable to its usage And since coal supplies far outstrip gas and oil reserves, interest in coal desulfurization is great Presently, however, there are no processes sufficiently developed, either technically or commercially, which have any significant impact on the industry The following is, therefore, 422 FOSSIL FUEL CLEANING PROCESSES a brief summary of the more pertinent processes currently under... removed through the bottom of the reactor The factors most directly affecting desulfurization are particle size, reactor residence time, reaction temperature and fluidizing velocity Figure 13 summarizes relationships between extent of desulfurization (expressed as the ratio of sulfur in char to that in feed-∆S) and above mentioned parameters Other processes, in various stages of development include causticized... desulfurization, gasification to high and low BTU Gases and extr action of pyritic sulfur from raw coal The Bureau of Mines, bituminous coal research and others have sought to remove sulfur (pyritic) by washing, using various techniques including centrifugation, flotation and magnetic separation methods None of these has the potential to remove more than half the sulfur and each leads to significant product... gravities above 2.0 for carbonates and silicates and as high as about 5.0 for pyrites Bowling et al.12 state that the levels of ash-forming mineral matter in most coals can be reduced by a combination of physical and chemical methods, to yield ultraclean coals with ash yields of 0.1–1% BLENDING WITH PETROLEUM COKE To satisfy a worldwide power production growth rate of more than 2.5% a year, with even... content and low grindability reduce solids handling costs The high vanadium content may, however, contribute to secondary plumes problems in the absence of sulfur removal equipment Ash Analysis, ppm nations in Asia and Latin America, nations are reviewing their fuel alternatives One such fuel is petroleum coke (PC), being produced at a worldwide rate of over 50 tons per year in 2000 PC is a byproduct of. .. refining that can be burned along with other fossil fuels The cement industry is currently one of the widest consumers of blended PC When co-firing liquid or gaseous fuel, PC will usually require additional control equipment for particulate and sulfur oxides reduction In boilers cofiring coal particulate controls may be adequate since PC ash REFERENCES 1 Myerboff, A.A., American Scientist 69, 624 (1981)... 8 Bartenope, D.P and E.N Ziegler, Enc of Env Sci and Eng 2, 837 (1975), 1st Edition, Gordon and Breach Sci Pub., New York (London) 9 Hoog, H.J Inst Petrol 36, 738 (1950) 10 Trowbridge, T.F., Chem Eng Prog 84, 26–33 (Mar 1988) 11 Bartok, W., R.K Lyon, A.D McIntyre, L.A Ruth and R.E Sommerlad, Chem Eng Prog 84, 54–71 (Mar 1988) 12 Bowling, K.M., H.W Rottendofr and A.B Waugh, J Inst of Energy 155, 179–184... a 200 mesh screen and slurried in an initial solvent oil The slurry is pumped to a pressure of 1,000 lb/sq.in and passed upwards through a heater to bring the slurry to a temperature of 45ЊC The flow rate is between a half and one space velocity As the material leaves the heater, more than 90% of the carbon in the coal is in solution (Anthracite coal is an exception.) A small amount of hydrogen is introduced... additional environmental concerns and fuel treatment procedures which are summarized below: • • • ozone formation—reduction of gasoline vapor pressure carbon monoxide emissions—add oxygenates to blend benzene emissions—reduce fraction in reformate by extraction for example DESULFURIZATION OF COAL Although coal buring accounts for only about 1/4 of the nation’s energy, approximately 2/3 of all the sulfur . Council. 3a The pre- dicted fossil fuel usage in terms of billions kwh electric gen- eration in the year 2015 is for coal-2000, natural gas-1000, nuclear-400, and petroleum-less than 100. Renewables. - ABSORBER R - REGENERATOR SK - SKIM TANK F - FILTER SULFUR CAKE FIGURE 10 © 2006 by Taylor & Francis Group, LLC 422 FOSSIL FUEL CLEANING PROCESSES a brief summary of the more pertinent processes. 411 FOSSIL FUEL CLEANING PROCESSES The amount of pollutants, especially sulfur oxides and par- ticulates emitted to the atmosphere may be reduced by treat- ing fuels prior to combustion.