Section 9 Energy Utilization, Conversion, and Resource Conservation Richard C. Corey, B.S., Department Staff (Retired), Energy Systems Engtneertng Department, The MITRE Corporation, Metrek Dtvtsion; Member, American Socfety of Mechanical Engtneers and Afr Pollutton Control Association. (Solid and Gaseous Fuels, Combustion, Fuel and Energy Costs, Coal Concerston, Ftred Process Equipment, Heat Transport and Regeneration). (Section Editor) Richard Barrett, MS., Projects Manager, Battelle Memortal Institute, Columbus Lab ratortes; Member, American Society of Mechanical Engtneers, American Society of Heating, Refrtgerattng, and Atr Condttiontng Engineers; Institute of Energy (United Kingdom); Reg- istered Professional Engineer (Ohio). (Steam Systems) Robert C. Amero, B.S., Stafi Engineer, Gulf Science and Technology Company (Rettred); Member, American Society of Mechanical Engineers, American Znstitute of Chemical Engineers, lnternattonal Association for Hydrogen Energy; Registered Profes- sional Engfneer (Pennsylcanta). (Liquid Fuels, Combustton) Harold F. Chambers, Jr., Ph.D., Supervisory Mechanical Engineer, Pittsburgh Energy Technology Center, U.S. Department of Energy; Registered Professional Engineer (Ohio). (Coal Liquefaction) Ezekail 1. Clark, B.S., Cmtsultant; Fellow, American Institute of Chemtcul Engineers; Member, Amertcun Chemical Society, American Assoctation for the Adcancement of Sct- ence; Registered Professional Engineer (Pennsylcunia). (Associate Sectton Editor; Coal G&cation) Neil H. Ceahs, B.S., Department Head, Energy Systems Engtneertng Department, The MZTRE Corporation, Metrek Dtcbfon. (Fluidfzed-Bed Combustion) Willard E. Fraize, Sc.D., Senior Energy Systems Engineer, Energy and Resources Dtvt- sion, The MITRE Corporation, Metrek Dtvtston; Member, American Society of Mechanical Engtneers, American Institute of Aeronautics and Astronautics. (Cogeneration) Yuan C. Fu, Ph.D., Project Manager, Ptttsburgh Energy Technology Center, U.S. Department of Energy; Member, American Chemical Society, The Chemtcul Society of lapan, Catalysts Society. (Coal Liquefaction) H. A. Grabowski, B.S., Senior Engineering Consultant, C-E Enoironmental Systems, Combustion Engfneertng Inc.; Member, American Society of Mechanical Engineers, Amer- ican Society for Testing and Mater&& (Steam Generators) Eugene Mezey, Ph.D., Senior Chemist, Battelle Memorial Znstttute, Columbus Labmu- tortes; Member, American Chemical Society, The Soctety of Sigma Xi, Zntemattonal Mtcro- wave Power Institute, American Ceramic Institute; Fellow, American Association for the Adcuncement of Science. (Electric Heating) David E. Stutz, B.S., Research Scientist, Battelle Memortal Institute, Columbus Labo- ratories; Member, International Microwave Power Institute. (Electric Heating) 9-1
Transcript
Section 9
Energy Utilization, Conversion, and
Resource Conservation
Richard C. Corey, B.S., Department Staff (Retired), Energy Systems Engtneertng Department, The MITRE Corporation, Metrek Dtvtsion; Member, American Socfety of Mechanical Engtneers and Afr Pollutton Control Association. (Solid and Gaseous Fuels, Combustion, Fuel and Energy Costs, Coal Concerston, Ftred Process Equipment, Heat Transport and Regeneration). (Section Editor)
Richard Barrett, MS., Projects Manager, Battelle Memortal Institute, Columbus Lab ratortes; Member, American Society of Mechanical Engtneers, American Society of Heating, Refrtgerattng, and Atr Condttiontng Engineers; Institute of Energy (United Kingdom); Reg- istered Professional Engineer (Ohio). (Steam Systems)
Robert C. Amero, B.S., Stafi Engineer, Gulf Science and Technology Company (Rettred); Member, American Society of Mechanical Engineers, American Znstitute of Chemical Engineers, lnternattonal Association for Hydrogen Energy; Registered Profes- sional Engfneer (Pennsylcanta). (Liquid Fuels, Combustton)
Harold F. Chambers, Jr., Ph.D., Supervisory Mechanical Engineer, Pittsburgh Energy Technology Center, U.S. Department of Energy; Registered Professional Engineer (Ohio). (Coal Liquefaction)
Ezekail 1. Clark, B.S., Cmtsultant; Fellow, American Institute of Chemtcul Engineers; Member, Amertcun Chemical Society, American Assoctation for the Adcancement of Sct- ence; Registered Professional Engineer (Pennsylcunia). (Associate Sectton Editor; Coal G&cation)
Neil H. Ceahs, B.S., Department Head, Energy Systems Engtneertng Department, The MZTRE Corporation, Metrek Dtcbfon. (Fluidfzed-Bed Combustion)
Willard E. Fraize, Sc.D., Senior Energy Systems Engineer, Energy and Resources Dtvt- sion, The MITRE Corporation, Metrek Dtvtston; Member, American Society of Mechanical Engtneers, American Institute of Aeronautics and Astronautics. (Cogeneration)
Yuan C. Fu, Ph.D., Project Manager, Ptttsburgh Energy Technology Center, U.S. Department of Energy; Member, American Chemical Society, The Chemtcul Society of lapan, Catalysts Society. (Coal Liquefaction)
H. A. Grabowski, B.S., Senior Engineering Consultant, C-E Enoironmental Systems, Combustion Engfneertng Inc.; Member, American Society of Mechanical Engineers, Amer- ican Society for Testing and Mater&& (Steam Generators)
Eugene Mezey, Ph.D., Senior Chemist, Battelle Memorial Znstttute, Columbus Labmu- tortes; Member, American Chemical Society, The Soctety of Sigma Xi, Zntemattonal Mtcro- wave Power Institute, American Ceramic Institute; Fellow, American Association for the Adcuncement of Science. (Electric Heating)
David E. Stutz, B.S., Research Scientist, Battelle Memortal Institute, Columbus Labo- ratories; Member, International Microwave Power Institute. (Electric Heating)
9-1
9-2 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Gaseous Fuels NaturalGes : : : Liquefied Natural Gas (LNG) Liquefied Petroleum Gas (LPG) Re-fomled Gas. OilGases ., .., Producer Gas Blue Water Gas, Carbureted Water Gas, and Coal Gas Blast-Furnace Gas Acetylene Hydrogen : : : : : : Sulfur impurities. Supercompressibility of Natural Gas
Fuel and Energy Costs Cd Conversion to Liquid and Gaseous Fuels and Feedstocks for the Chemical-Process Industries
Coal Gasification. Background Theoretical Considerations Types of Available Gasification Equipment Development and Lltilization Application of COPI Gas&cation Gas Purification and Refinement Economics of Coal Gasification.
Direct Coal Liquefaction Background Direct-Liquefaction Kinetics Direct-Liquefaction Processes Coal-Pyrolysis Pr-
Indirect Coal Liquefaction Fischer-Tropsch Synthesis Methanol-t+Gasoline Process. Syngas-to-Gasoline Process
Ecunomia of Coal Liquefaction
HEAT GENERATION Combustion Stoichiometry
Theoretical Oxygen and Air for Combustion Excess Air for Combustion Products of Combustion
Enthalpy of Combustion Products. Solid-Fuels Combustion on Stokers and in Suspension
c Relative magnetic Dimensionless Dimensionkss permeability
P Density kg/m3 Ib/ft3
* Shaue factor
FUELS
RESOURCES AND RESERVES
The resow- and reserves of the principal fossil fuels in the United States-coal, petroleum, and natural gas-follow:
Quintillion (10”) Btu
Fuel
Potential Known economic Submarginal reserves resnurces reso”*ces
cd Petroleum liquids (crude and
natural-gas liquids) Natural gas
4.8 3.0 25.0
0.26 2.7 14.0 0.30 2.1 4.5
Conversion factors
Bituminous and anthracite coal 30.2 I/kg (26 X ld Btu/ton) Lignite and subbituminous coal 23.2 l/kg (20 X 10e Btu/ton) Crude oil 38.4 j/L (5.8 X l@ Btu/bbl)’ Natural-gas liquids (4.6 X Id Btujbbl)’ Natural gas Z”,“% J/m3 (1032 Btu/ft’)
I bbl = 42 gal = 159 L = 0.159 m?
SOLID FUELS
Coal
G-R * Elliott (ed), Chemictry of Coal Uttltitron, 2d suppl. vol., Wiley. New York, 1981. Van Krevelen. Conf, Ebvier. Amsterdam, 1961.
TARLR 9-1 Cfauiffcation of Coah by Rank*
origin Coal originated from the arrested decay of the remains of trees, bushes, ferns, mosses, vines, and other forms of plant life which tlourished in huge swamps and bogs many millions of years ago during prolonged periods of humid, tropical climate and abun- dant rainfall. The precursor of coal was peat, which was formed by bacterial and chemical action on the plant debris. Subsequent actions of heat, pressure, and other physical phenomena metamorphosed the peat to the various ranks of coal as we know them today. Because of the various degrees of the metamorphic changes during this process, coal is not a uniform substance; no two coals are ever the same in every respect.
Ckaseijcation of Cod Coals are classified by rank, i.e., acoord- ing to the degree of metamorphism in the series from lignite to anthracite. Table Q-l shows the classification system adopted by the American Society for Testing and Materials, DUS-77. The heating value on the moist, mineral-matter-free (mmf) basis and the fixed carbon, on the dry mmf basis, are the bases of this system. The lower- rank coals are classified according to the heating value, J/kg (Btu/ lb), on the moist mmf ha&s. The agglomerating character is used to differentiate between adjacent groups. Coals are considered agglom- erating if the coke button remaining from the test for volatile matter will support a weight of 500 g or if the button swells or has a porous cell structure.
ThP Parr fnrmulac. Fo< (Q-1) to (9-S). or the approximation for- mulas, Eqs. (9-4) and (95), are used for classifying coals according to rank. The Parr formulas are employed in litigation cases.
lOOfF - 0.15s) F’ =
100 - (M + LOftA + 0.55s) (9-L)
Fixed carbon limits, 96 (dry
mmf basis)
Volatile matter C&r& value limits. W (dry mmf limits, Btu/lbb
High-volatile A bituminous COPI High-volatile B bituminous coal High-volatile C bituminous coal
Ivb 78 mvb hvAb 6:
hvBb hbCb
14 22 31
Equal or Ekpal or greater less than than
2 8
14
22 31
14.w
Less Agglomerating than character
II Nonagglomerating
Subbituminous A COPI SubA S&bituminous Subbituminous B coal SubB
S&bituminous C coal SUbC
Lignitic Lignite A IigA Lignite B IigB
‘Annual Book of ASTM Stan&&, part 26, D 388-77.1977. This classification dm not include a few coats, principally nonbanded varieties. which have unusual ohvsical and chemical oronertin and which come within the limits of fixed carbon or calortfic value of the hinh-volatile bituminous and subbituminous ranks. All &se cvab either cc&n iesJ that 48% dry mmf fixed carbon or have more that 15,500 moist mmf Btu/lb. I
“To convert British thermal units per pound to joules per kilogram. multiply by 2326. %4&t refers to coal containing its natural inherent moisture but not includinc visible water on the surface of the ccal. dlf agglomerating, classify in l&-w-volatile group of the bituminous claw _ ‘Coals having 6996 or more fixed carbon on the dry mmf basis are classified according to fixed carbon regardless of c&r&c value. ‘There may he nonagglomerating varieties in these groups of the bituminous clas. and there are notable exceptions in the high-volatile C bituminous group.
9-3
V’ = 100 - F’ (2-2)
Q= lOO(Q - SOS)
100 - (1.08A + 0.55s) (9-W
16,000
14,000
t
F’ = 1OOF
100 - (M + l.lA + 0.1s)
Q- 1mQ
100 - (l.lA + 0.1s)
where M, F, A, and S are weight percentages, on a moist basis, respectively of moisture, fixed carbon, ash, and sulfur; F’ and V’ are weight percentages, on a dry mmf basis, respectively of fixed carbon and volatile matter; Q and Q’ are calorific values, Btu/lb (X 2326 = J/kg), respectively on a moist non-mmf basis and a moist mmf basii.
Table 9-2 shows the principal ranks of coal mined in the major coal-producing states of the United States.
Comporition and Heating Value of Coal The composition of coal is generally reported in two different ways, the proximate anal- ysis and the ultimate analysis, both expressed in weight percent. The proximate analysis is the determination by prescribed methods of moisture, volatile matter, fixed carbon, and ash. Figure 9-1 gives the proximate analyses and heating values, on a moist mmf basis, of the various ranks of coal. It is seen that the fixed carbon and heating values increase with an increase in rank and that the moisture and volatile matter decrease.
The total moisture in coal consists of inherent moisture and bed moisture. Inherent moisture, also referred to as bed and equilibrium moisture, exists as a quality of a coal seam in its natural state of depo sition. Free moisture, also referred to as surface moisture, is the part of the total moisture that is lost when coal is air-dried under standard conditions.
The volatile matter is the portion of the coal which, when heated
FIG. 9-1 Heating values and proximate analyses of coal on a moist, mineral- matter-free basis. To convert British thermal units per pound to joules per kilo-
gram, multiply by 2326.
in the absence of air under prescribed conditions, is liberated as gases and vapors. Volatile matter does not exist by itself in coal, except for a little absorbed methane, but results from thermal decomposition of the coal substance.
Fixed carbon is the residue left after the volatile matter is driven off and is calculated by subtracting from 100 the percentages of moisture, volatile matter, and ash of the proximate analysis. In addi- tion to carbon, it may contain several tenths of a percent of hydrogen and oxygen, 0.4 to 1.0 percent nitrogen, and about half of the sulfur that was in the coal.
Ash is the inorganic residue that remains after the coal has been burned under specified conditions, and it is composed largely of compounds of silicon, aluminum, iron, and calcium and of minor amounts of compounds of magnesium, sodium, potassium, and tita- nium. Ash may vary considerably from the original mineral matter, which is largely kaolinite, illite, montmorillonite, quartz, pyrites, and gypsum.
The ultimate analysis is the determination by prescribed methods of the ash, carbon, hydrogen, nitrogen, oxygen (by difference), and sulfur. Along with these analyses, the heating value, expressed as joules per kilogram (British thermal units per pound), is also deter- mined. This is the heat produced at constant volume by the complete combustion of a unit quantity of coal in an oxygen-bomb calorimeter under specified conditions. The result includes the latent heat of vaporixation of the water in the combustion products and is called the gross heating or high heating value (HHV), Qh. The heating value when the water is not condensed is called the low heating value (LHV), Qt, and is obtained from
QI = Qh - 103Ow (g-6)
where W = lb water formed/lb of fuel. The factor 1030 converts the high heating value at constant volume to low heating value at constant pressure. When dealing with gases, a useful equation is
QI = Qh - (859 PO/T) (9-6a)
aal Ranks of 6al Mined in Various States*
L ‘Compiled large :ly
U.S. Bur. Mines Bull. Gad. Survey Bull. 1136
- 0 ” E:
32 e ‘I 44
-
x
x
x x
x
x
,ica Ite
jta
TABLE 9-2 Print
item
Alabama
Alaska Arkansas Colorado Illinois Indiana
Iowa Kansas : : Kenhrcky:
Eastern.
Western Maryland. Missouri Montana New Mexico
North Dakota. Ohio Oklahoma
Pennsylvania
South Dakota.
Tennessee Texas Utah : : : : Virginia
Washington. West Virginia
Wyoming.
SOUD FUELS 9-5
where QI and Qh = Btu/fts of gas p = pressure, of mercury o = fts water in combustion products/fts fuel T = temperature, OR
For 60F and 29.92 inHg, the equation simplifies to
QI = Qj, - 49.40 (9-s&)
Q,+ in Btu/lb (X 2326 = J/kg) can be approximated by a formula developed by the Institute of Gas Technology;
where C, H, S, A, 0, and N are respectively the weight percentages on a dry basis of carbon, hydrogen, sulfur, ash, oxygen, and nitrogen. The standard deviation for 775 coal samples is 127.
FIG. 9-2 Estimated remaining coal reserves of all ranks, by sulfur content. in the United States, Jan. 1. 1965. (From U.S. Bur. Mhes In. Clrc. 8312.)
Coal analyses are reported on several bases, and it is customary to select the basis best suited to the application. The as-received basis represents the weight percentage of each constituent in the sample as received in the laboratory. The sample itself may be coal as fired, as mined, or as prepared for a particular use. The moisture-free (dry) bans IS generally the rnosr useful bans because performance calculations can be easily corrected for the actual moisture content at the point of use. The dry, ash-free basis is frequently used to approximate the rank and source of a coal. For example, the heating value of coals of a given source and rank is remarkably constant when calculated on this basis. Use of these bases is illustrated in Table 9-3.
Laboratory procedures for proximate and ultimate analyses are given in the Annual Book of ASTM Standards, part 26, 1977; and in Methods of Analysing and Testing Coal and Coke, U.S. Bureau of Mines Bulletin 638, 1967.
tures. The difference between the softening and initial-deformation temperatures is called the softening interval, and that between the fluid temperature and the softening temperature is called the fluid interval. The fusibility of coal ash is determined by ASTM D 1857, Annual Book of ASTM Standords, part 26, 1977. The softening tem- poraiture in mart o&err “red IS pr rough qunlitativ~ gaGlr= tn th.= Lhav- ior of ash on a grate and on furnace heat-transfer surfaces, with respect to the tendency to form large masses of sintered or fused ash, which impair heat transfer and impede gas Row. Likewise, the fluid temperature and the fluid interval are qualitative guides to the “Eow- ability” of ash in a slag-tap furnace. However, because ash fusibility is not an infallible index of ash behavior in practice, care is needed in using ash-fusibility data for designing and operating purposes. There is an excellent discussion of this subject in Steam: Its Cener- atton and Use, Babcock & Wilcox Co., New York, 1978.
The composition of coal ash varies widely. Calculated as oxides, the composition (percent by weight) varies as follows:
Sulfur in Coal Efforts to abate atmospheric pollution have drawn considerable attention to the sulfur content of coal, since the combustion of coal results in the discharge to the atmosphere of sul- fur oxides. Sulfur occurs in coal in three forms: as pyrites (Fe&); as organic sulfur, which is a part of the coal substance; and as sulfate sulfur. The sulfate sulfur comprises at the most only a few hun- dredths of a percent of the coal. The organic sulfur may comprise from 20 to 80 percent of the total sulfur. Since organic sulfur is chemically bound to the coal substance in a complex manner, drastic treatment is necessary to break the chemical bonds before the sulfur can be removed. There is no economic method known at present that will remove organic sulfur, but progress is being made with so-called chemical methods for cleaning coal. Pyritic sulfur can be partially removed by using standard coal-washing equipment. The degree of pyrite removal depends on the size of the coal and the size and dis- tribution of the pyrite particles.
SiOp Ais@ Fe&is GO MgO TiOe NanO and KaO SOS
20-60 lo-35 5-3.5 l-20
0.3-4 0.5-2.5
l-4 0.1-12
The sulfur content of United States coals varies widely, ranging from a low of 0.2 percent to as much as 7 percent by weight, on a dry basis. The estimated remaining United States coal reserves of all ranks, by sulfur content, are shown in Fi 9-2. Extensive data on
s sultur in United States coals are given in U. Bureau of Mines Infor- mation Circular 8312. The sulfur reduction potential of United States coals is described in U.S. Bureau of Mines Information Circular 8118, which gives washability data for 455 raw-coal samples.
Coal-Ash Characterietics and Composition When coal is to be burned or gasified, it is important to determine the ash fusibility, comprising the initial deformation, softening, and fluid tempera-
Knowledge of the composition of coal ash is useful for estimating slagging and clinkering in fuel beds, predicting the flow properties of coal-ash slag (U.S. Bur. of Mines Bull. 618) in slag-tap and cyclone furnaces, and predicting, to a limited extent, the fouling and corro- sion of heat-exchange surfaces in pulverized-coal-fired furnaces.
Multiple correlations for ash composition and ash fusibility are dis- cussed in the Coal Cowersion Systems Technical Data Book, part IA, U.S. Department of Energy, 1978.
The alas rixosit)r-tempxoiturc; rc;latioruhip for oomplatcly malted slag is
Log viscosity = 10’ M/(T - 150)’ + C (9-8)
where viscosity is in poises (X 0.1 = Pa.s), M = 0.00835 (SiOa) + 0.00601 (AlaOa) - 0.109, C = 0.0415 (SiOa) + 0.0192 (AlsOs) + 0.0276 (equivalent FeaOs) + 0.0160 (CaO) - 3.92, and T = “C.
TABLE 9-3 Comparison of gases for Coal Analyses; High-Volatile A Bituminous Coal, Allegheny County, Pa., Pittsburgh &d
‘On the as-received basis, the hydrogen and oxygen include the hydrogen and oxygen of the moisture NOTE: To convert British thermal units per pound to joules per kilogram. multiply by 2326.
9-6 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TABLE 94 Spocimon Frntwelling and Hardgrow Grindability Indies
state Name of bed
Free-swelling index (FSI) Hardgrove grindability index (HGI)
The oxides in parentheses are the weight percentages of these oxides when SiOs + A1sOs + FesOs + CaO + MgO = 100.
Z’hyrical Propertier of Coal The free-swelling index (FSI) measures the tendency of a coal to swell when burned or gasified in fixed or fluidized bed. Coals with a high free-swelling index (>4) can usually be expected to cause difficulties in such beds. Details of the test are given in ASTM D 720, Annual Book of ASTM Stan- dards. part 26, 1977; and U.S. Bureau of Mines Report of Investiga- tions 3989.
The Hardgrove grindability index (HGI) indicates the ease (or difficulty) of grinding coal and is complexly related to physical prop- erties such as hardness, fracture, and tensile strength. The Hardgrove machine is usually employed (see ASTM D 409). It determines the relative grindability or ease of pulverizing coal in comparison with a standard coal, chosen as 100 grindability (see Sec. 8). The FSI and HGI of some United States coals are given in Table 9-4. See Bureau of Mines Information Circular 8025 for FSI and HGI data for 2812 and 2339 samples respectively.
The bulk density of broken coal varies according to the specific gravity, size distribution, and moisture content of the coal and the amount of settling when the coal is piled. Following are some useful approximations of the bulk density of various ranks of coal:
Size stability refers to the ability of coal to withstand breakage during handling and shipping. It is determined by twice dropping a 22.7-kg (5OJb) sample of coal from a height of 1.83 m (6 ft) onto a steel plate. From the size distribution before and after the test, the size stability is reported as a percentage factor (see ASTM D 440). The frfabfltty test measures the tendency of coal to break during repeated handling. It is actually the complement of size stability and is determined by the standard tumbler test (ASTM D 441-45).
Spiers’s Tech&al Data on Fuels gives the specific heat of dry, ash-free coal as follows:
The relationship between specific heat and water content and between specific heat and ash content is linear. Given the specific heat on a dry, ash-free basis, it can be corrected to an as-received basis. The specific heat and enthalpy of coal to 1090°C (2000°F) are given in Coal Conoersfon Systems Technical Data Book, part IA, U.S. Department of Energy, 1978.
The mean specific heat of coal ash and slag, which is used for calculating heat balances on furnaces, gasifiers, and other coal-con- suming systems, follows:
Coke Coke is the solid, cellular, infusible material remaining after the carbonization of coal, pitch, petroleum residues, and certain other carbonaceous materials. The varieties of coke, other than those from coal, generally are identified by prefixing a word to indicate the source. e.e.. oetroleum coke. To indicate the mocess bv which a
_I_~ ,
coke is manufactured. a orefix also is often used. e.e.. own coke. Transformutbn of coal info coke. The mechanism of the for-
mation if coke whencoal is carbonized is a complex of physical and chemical phenomena that are not perfectly understood. Some of the physical changes, which are interrelated when certain ranks of coal or blends are heated, are softening, devolatilization, swelling, and resolidification. Some of the accompanying chemical changes are cracking, depolymerization, polymerisation, and condensation. More detailed theoretical information is given in Coal, by Van Krevelen (Elsevier, Amsterdam, 1961), and Chemistry of Coal Ufiltzatfon, by Lowry (Wiley, New York, 1945 and 1963).
High-temperature coke (900 to 115O’X). This type is most com- monly used in the United States; nearly 20 percent of the total bitu- minous coal consumed is used to make high-temperature coke for metallurgical applications. About 99 percent of this type of coke is made in slot-type recovery ovens, and the remainder in beehive and other types of ovens. Blast furnaces use about 90 percent of the pro- duction, the rest going mainly to foundries and gas plants.
A U.S. Bureau of Mines survey of 12 blast-furnace coke plants, whose capacity is 30 percent of the total production in the United States, provides an excellent picture of the acceptable chemical and physical properties of such coke. The ranges of properties are given in Table 9-5.
The typical by-product yields per ton of dry coal from high-tem- perature carbonization in ovens, with inner-wall temperatures from 1000 to 1150% (1832 to 2102OF). are: coke, 653 kg; gas, 154 kg (11,200 f?); tar, 44 kg (10 gal); water, 38 kg; light oil, 11 kg (3.3 gal); and ammonia, 2.2 kg.
Foundry coke. This coke has different requirements from blast- furnace coke. The volatile matter should not exceed 2.0 percent, the sulfur should not exceed 0.7 percent, the ash should not exceed 12.0 percent, and the size should exceed 3 in.
Low- and medium-temperature coke (500 to 75OOC). Cokes of this type are not now produced in the United States to a significant extent. However, there is now interest in low-temperature carboni- zation as a source of both hydrocarbon liquids and gases to supple- ment petroleum and natural-gas resources.
The Fischer assay is an arbitrary but precise analytical tool for determining the yield of products from low-temperature carboniza- tion. A known weight of coal is heated at a controlled rate in the absence of air to 500°C, and the products are collected and weighed.
TABLE 9-5 Chemical and Physical Pqwtios of High-TomPwaturo Cokes Used in tha United States’
‘Comparison of Properties of Coke Produced by EM-ACA and Indwwal Methods. U.S. Bur. Mines Rep. Invest. 6354. To convert inches to centimeten. multiply by 2.54.
SOLID FUELS 9-7
TABLE 9-6 Fiihw-Assay Yields from Various Ranks of Cool (As-R~~oivod Basis)
ASTM classification by rank Coke. Tar, Light oil, GPS, water,
ClasS Group weight % gal/ton gal/ton ftS/ton weight %
Subbituminous 1. Subbituminous A 59 20.5 1.7 2660 23 2. Subbituminous B 56 15.4 1.3 2260 26
Lignite 1. Lignite A 37 15.2 1.2 2100 44
NOTE To convert gallons per to” to liters per kilogram, multiply by 0.004; to convert cubic feet per ton to cubic meters per kilogram. multiply by 3.1 X lo-‘.
Table 9-6 gives the approximate yields of products for various ranks of coal.
Pitch coke and petroleum coke. Pitch coke is made from coal- tar pitch, and petroleum coke is made from petroleum residues from petroleum refining. Pitch coke has about 1.0 percent volatile matter, 1.0 percent ash, and less than 0.5 percent sulfur on the as-received basis. There are two kinds of petroleum coke: delayed coke and Buid coke. Since they contain the impurities from the original crude oil, the sulfur is usually high, and appreciable vanadium salts may be present. Ranges of composition and properties are as follows:
~
Other Solid Fuels
Char Char is the nonagglomerated, nonfusible residue from the thermal treatment of solid carbonaceous material. Coal chars are obtained as a residue or a coproduct from low-termperature carbon- i&ion processes and from processes being developed to convert coal to liquid and gaseous fuels and to chemicals. Such chars have a sub stantial heating value. The net amount of char from a conversion pr- varies widely; in some instances it may represent between about 30 and 55 percent of the weight of coal feed; in others no net or excess char is produced; i.e., the entire char yield is consumed as in-plant fuel. The analyses of feed coals and resulting chars from two coal-conversion processes are given in Table 9-7. The volatile matter, sulfur, and heating values of the chars are lower, and the ash is higher, than in the original coal.
Wood Higher heating values are 20,004 X 109 J/oven-dried kg of hardwood species and 20,930 X 10s J/oven-dried kg of softwood
TABLE 9-7 Examples of Anab of Coal Feeds and Resulting Char Rot-•
Sfr
species. These values are accurate enough for most engineering pur- poses. U.S. Department of Agriculture Handbook 72 (revised 1974) gives the specific gravity of the important softwoods and hardwoods if heating value on a volume basii is needed.
Peat Peat is partially decomposed plant matter that has accu- mulated underwater or in a water-saturated environment. It was the precursor of coal but is not classified as coal. Peat is sold under the term “peat moss” or “moss peat” and currently is used in the United States mainly for horticultural and agricultural applications. Interest is growing in its use as a fuel in certain local areas. Although analyses of peat vary widely, a typical high-grade peat has 90 percent water, 3 percent fixed carbon, 5 percent volatile matter, I.5 percent ash, and 0.10 percent sulfur. The moisture-free heating value is approx- imately 20,930 X 10s J/kg (9000 Btu/lb).
Ckrcool Charcoal is the residue from the destructive distilla- tion of wood. It absorbs moisture readily, often containing as much as 10 to 15 percent water. In addition, it usually contains about 2 to 3 percent ash and 0.5 to 1.0 percent hydrogen. The heating value of charcoal is about 27,912 X 10s to 30,238 X 10s J/kg (12,000 to 13.000 Btu/lb).
Tanbark Tanbark is the residue remaining after bark has been used in tanning operations. It usually contains from 60 to 70 percent water and has a heating value of 5815 X ld to 6978 X 10s J/kg (2500 to 3000 Btu/lb). -
Bogarre Bagasse is the solid residue remaining after sugarcane has been crushed by pressure rolls. It usually contains from 40 to 50 percent water. The dry bagasse has a heating value of 18.608 X 10s to 20,934 X 10s J/kg (8000 to 9000 Btu/lb).
Solid Wartee and Biomarr Large and increasing quantities of solid wastes generated per capita are a significant feature of affluent societies. In the United States the rate exceeds 5 lb per capita per day, or nearly 290 million tons per year, and it is grooving rapidly. Table 9-8 shows the composition of various solid wastes. On a mois- ture-free basil, the composition of miscellaneous refuse is surpris- ingly uniform, but size and moisture variations cause malor difficul- ties in efficient, economical disposal.
‘Nelson et al.. Study of the Idenrificatla and Assessment of Potenttil Markets for Chars from Various Procesc(ng Systems, Battek Memorial Institute, Columbus. To convert Brlthh therrnal units per pound to joules per kilogram, multiply by 2326.
tFMC pr- involves multistage tluidized-bed pyrolysis of coal to produce a liquid, residual char, and some gas. tiGT process involves hydrogasification of coal to produce a gas of pipe-line quality (about loo0 Btu/ft’) and char.
9-8 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
‘From Hescheles, MECAR Conference on Waste LX.qwd, New York, 1968; and Refuse Collection Practfce, 3d ed.. American Public Works Association, Chicago, 1966. To convert British thermal units per pound to joules per kilogram, multiply by 2.326: to convert pounds per cubic font to kilograms per cubic meter, multiply by 16.02.
The fuel value of most solid wastes is usually sufficient to enable self-supporting combustion, leaving only the incombustible residue and reducing the volume of waste eventually consigned to sanitary landfill to only 10 to 15 percent of the original volume. The heat released by the combustion of waste can be recovered and utilized, although the cost of the recovery equipment or the distance to a suit- able point of use for the heat may make heat recovery economically infeasible.
equipment designed for oil bnd gas without significant derating or expensive retrofit work, with about 50 percent coal by weight. It is generally agreed that COM is not economically attractive for boilers producing less steam than 45,360 kg/h (100,000 lb/h).
COMs are nonnewtonian &ids in the pseudoplastic classification; that is, their viscosities decrease with increasing velocity gradient. Once COMs start Bowing, their viscous nature approaches that of a heavy oil.
Biomass (e.g., crop residues and cattle manure) is an important source of energy currently being examined for engineering feasibil- ity and economics. Energy from Biocm~sion of Waste Mat&ah, by D. J. DeRenzo (Noyes Data Corp., Park Ridge, N.J., 1977), is a useful reference.
A useful reference for COMs is “Can Coal-Oil Mixtures Make It as Industrial Fuels?” by J. W. Eberle and R. H. Hickman [Me&. Eng., 24-28 (March 1978)].
Coal-Oil Mixture (COM) COM is viewed as a near-term method for extending domestic fuel supplies and for reducing for- eign oil imports. The most attractive feature of the COM concept is that the technology for producing and burning coal-oil slurries exists; they can be burned in many existing boilers with few modifications.
Coal for the mixture is pulverized wet or dry until about 80 per- cent passes through a 200-mesh screen. Then it is blended with oil and a surfactant, which helps keep the coal in suspension. Boiler tests indicate that COM can be burned in boilers and some fired process
UQUID FUELS
Liquid Petroleum Fuels The principal liquid fuels are made by fractional distillation of crude petroleum (a mixture of hydrocarbons and hydrocarbon derivatives ranging from methane to heavy bitu- men). As many as one-quarter to one-half of the molecules in crude may contain sulfur atoms; and some contain nitrogen, oxygen, van- adium, nickel, or arsenic. Desulfurization, hydrogenation, cracking (to lower molecular weight), and other refining processes may be performed on selected fractions before they are blended and mar-
-
Density: 15OC 2 2
I III,rlll I I1111111 I I I I lllll I I1111111 I I lllll(
0.1 1 10 lal 1000 ia ‘00 Kinematic viscosity at 100 OF, mm2/s St)
Ho. 9-3 Viscosity, boiling-range, and gravity relationships for petroleum fuels.
LIQUID FUELS 9-9
keted as fuels. Viscosity-gravity-boiling-range relationships of com- mon fuels are shown in Fig. 9-3.
The highly viscous oil extracted from tar sands is also a grade of crude petroleum which can be hydrogenated and refined into con- ventional petroleum products.
Speci$cacatione Specifications developed by the American Soci- ety for Testing and Materials are widely used to classify fuels. Table 9-9 shows ASTM Fuel Oil Specihcation D 396. Note footnote F, cov- ering low-sulfur residual fuels of high wax content, which require the same heated storage and handling as No. 6 hut, when warm, are in the No. 4 or No. 5 viscosity range. (D 396 omits kerosine, a low- sulfur, clean-burning No. 1 fuel for lamps and freestanding flueless domestic heaters that is covered by Federal Specification VV-K- 2IId.)
In drawing contracts and making acceptance tests, refer to ASTM Standards, Parts 23 and 24 (American Society for Testing and Mate- rials, Philadelphia, annually). Part 23 contains test methods and spec- ifications (&s&cations) for burner fuel, motor and aviation gaso- line, diesel fuel, and aviation and gas-turbine fuel. It also contains ASTM D 270, with sampling procedures for bulk oil in tanks, barges, etc. Part 24 contains test procedures for water and sediment and alternative procedures for sulfur determination.
Fuel specifications from different sources may differ in test limits on sulfur, density, etc., but the same general categories are recog- nized worldwide: kerosine-type vaporizing fuel, distillate (or “gas oil”) for atomizing burners, and more viscous blends and residuals for commerce and heavy industry. Typical specifications are as follows:
Soecifier NUlllb.X Catenorv
Canadian Government Specification 5GP-2 Board, Department of Defence
Fuel oil, heating
Production, Ottawa, Canada
Deutschen Normenawhusses. DIN 51803 Heating (fuel) oils Berlin 15
British Standards Institution, British B.S. 2869 Petroleum fuels for oil Standards House, 2 Park Street, engines and burners London, WlA 2Bs
J”P”” ,IS IcL109 E%rori..e JIS K2204 Gas oil JIS K2205 Fuel oils
Federal swxifications. United States VV-F-815 Fuel oil. burner
Foreign specifications are generally available from the American National Standards Institute, New York; United States federal spec- ifications, at Naval Publications and Forms, Philadelphia.
Equipment manufacturers and large-volume users often write fuel specifications to suit particular equipment, operating conditions, and economics. Nonstandard test procedures and restrictive test limits should be avoided; they reduce the availability of fuel and increase its cost.
Bunker-fuel specifications for merchant vessels often cover only viscosity, flash point, water and sediment, and ash content. Deep- draft vessels carry residual (e.g., No. 6 fuel oil) or distillate-residual blend for main propulsion, plus distillate for startup, shutdown, maneuvering, deck engines, and diesel generators. Main-propulsion fuel is identified by its viscosity in centistokes at 50°C (e.g., “marine diesel 40”). Obsolete designations include those based on Redwood No. 1 seconds at lOOoF (e.g., “MD 1500”) and the designations “Bunker A” for No. 5 fuel oil and “Bunker B and C” for No. 6 fuel oil in the lower- and upper-viscosity ranges respectively.
Chemical and Physical Properties Petroleum fuels contain paraffins, isoparaffins, aromatics, and naphthenes, plus organic sulfur, oxygen, and nitrogen compounds that were not removed by refining. Olehns are absent or negligible except when created by severe refin- ing. Vacuum-tower distillates with a final boiling point equivalent to 454 to 566% (850 to 1050°F) at atmospheric pressure may contain from 0.1 to 0.5 ppm vanadium and nickel, but these metal-bearing compounds do not distil1 into No. 1 and 2 fuel oils.
Black, viscous residuum directly from the still at 200°C or higher
may serve as fuel in nearby furnaces or may be cooled and blended to make commercial fuels. Diluted with 5 to 20 percent distillate, the blend is No. 6 fuel oil. With 20 to 50 percent distillate, it becomes No. 4 and No. 5 fuel oils for commercial use, as in schools and apart- ment houses. Distillate-residual blends also serve as diesel fuel in large stationary and marine engines. However, distillates with inad- equate solvent power will precipitate asphaltenes and other high- molecular-weight Colloids from “visbroken” (severely heated) resid- uals. A blotter test, ASTM D 2781, will detect sludge in pilot blends. Tests employing centrifuges, filtration, or microscopic examination havealsobeenused.
No. 6 fuel oil contains from 10 to 500 ppm vanadium and nickel in complex organic molecules, principally porphyrins. These cannot be removed economically, except incidentally during severe hydrc- desulfurization (Amero, Silver, and Yanik, “Hydrodesulfurized Residual Oils as Gas Turbine Fuels,” ASME Pap. 75-WA/GT-8). Salt, sand, rust, and dirt may also be present, giving No. 6 a typical ash content of 0.01 to 0.5 percent by weight.
Ultimate analyses of some typical fuels are shown in Table 9-10. Hydrogen content of petroleum fuels can be calculated from den-
sity with the following formula, with an accuracy of about 1 percent for petroleum liquids that contain no sulfur, water, or ash:
H = 26 - 15s (9-9)
where H = percent hydrogen and s = relative density at 15OC (spe- cific gravity at 60“/60°F). Schmidt (Fuel oil Manual, 3d ed., Indus- trial Press, New York, 1969) claims improved precision of the for- mula by replacing 26 with different constants:
API Relative fuel density at 15°C gravity Constant
Gravity is usually determined at ambient temperature with spe- c;ialimed hydrometcn end cxprcwd in deg.-s API (at 60°F), P x~lo that relates inversely to specific gravity s at 60°/600F as follows (see also the abscissa scale of Fig. 9-4):
Degrees API = 141.5/e - 131.5 (9-10)
Specific gravity is widely used in countries outside the United States, and with the adoption of SI units the American Petroleum Institute favors density at 15OC instead of degrees API.
The hydrogen content, heat of combustion, thermal expansion, specific heat, and thermal-conductivity data herein were abstracted from Bureau of Standards Miscellaneous Publication 97, Thermal Properties of Petroleum Products. These data are widely used, although newer correlations have appeared, notably that by Linden and Othmer [C/rem. Eng., 54(4,5) (April and May 1947)].
Heat of combustion can be estimated within 1 percent from fuel gravity by using Fig. 9-4. Corrections for water and sediment must be applied for residual fuels, but they are insignificant for clean distillates.
Figure 9-5 shows viscosity-temperature relationships for typical petroleum fuels. Between the cloud point and the boiling point and at pressures below 6.9 MPa (1000 Ibf/in*), they are practically new- tonian liquids. At low temperatures where solids begin to separate, viscosity depends on the rate of shear.
Pour point ranges from -60°C ( -80°F) for some kerosine-type jet fuels to 46°C (115“F) for waxy No. 6 fuel oils. Cloud point (which is not measured on opaque fuels) is 5 or 10°C higher than pour point unless the pour has been depressed by additives.
The drop in viscosity with increasing temperature is greater for some fuels than for others. Generalized viscosity charts hecome less reliable at temperatures substantially removed from the specification temperatures of 38 or 50% (100 or 122OF).
9-10 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TAME 93 ASTM D 396-Note 79: Dotaibd Roauhnont for Fuel Oib’
Water and
sediment, volume
96
Distillation temperatures, “C (OF) Flash point.
(Z,
Min.
Ash, weight
96 lint 90%
Min.
point
Max Grade of fuel oil
-6’ (20)
-6’ (20)
c
0.10
0.10
1.10
215 (420)
No. 1: P distillate oil intended for vapwizing pot-type burners and other burners requiring this grade of fuel
No. 2: P distillate oil for general-purpose heating for we in burners not requiring No. 1 fuel oil
No. 4: preheating not usually required for handling or burning
No. 5 (light): preheating may be required, depending on climate and equipment
No. 5 (heavy): preheating m*y be required for burning and, in cold climates, for handling
No. 6. preheating required for burning and handling
:tepripted. with permission, from the Annual Book of Standor& _ . “tt is the intent ot these ctassitications that failure to meet any requirement of P given grade dm not automatically place a” oil in the next lower grade unless
in fact it meets all requirements of the lower grade. aln countries outside the United States other sulfur limits may apply. CLmver or higher pour points may be specified whenever required by conditions of storage or use. When a pour point less than - 18’C (0°F) is specified, the
minimum viscosity for grade No. 2 shall be 1.7 cSt (31.5 SUS) and the minimum 90% point shall be waived. “Viscwity value in parentheses are for information only and not oece+rprily limiting. “The amount of water by distillation plus the sediment by extraction shall not exceed 2.00%. The amount of sediment by extraction shall not exceed 0.50%. A
deduction in quantity shall be made for all water and sediment in excess of 1.0%. ‘Where low-sulfur fuel oil is required. fuel oil falling in the virosity range of a lower numbered grade down to and including No. 4 mpy be sup
agreement between purchaser and supplier. The visc&ty range of the initial shipment shall be identified, and advance notice shall be required when c lied by
R,. “gmg from one viscosity range to another. This notice shall be in sufficient time to permit the user to make the necessary adjustments.
‘Where low-sulfur fuel oil is reauired. Grade 6 fuel oil will be clpsified as low DOUI + 15OC (60°F) max., or high pour (DO max.). Low-pour fuel oil should be used u&s all tanks and lines are t&ted.
Thermal expansion of petroleum fuels can be estimated as volume change per unit volume per degree:
c = (1.685 + 0.0(x39 x “C)/s (g-11) c’ = (0.388 + 0.00045 X “F)/s (9-M
where c = heat capacity, kJ/(kg.OC) c’ = heat capacity, Btu/(lb.‘F) s = relative density at 15% (specific gravity, 60/60°F)
Specific heat varies with temperature, and an arithmetic average of the specific heats at the initial and final temperatures can be used for calculations related to the heating or cooling of oil.
Tabk V-10. Typical Uhimato Analyses of Potium Fuob
Density Volume change/unit volume
kg/dm’, lS°C API gravity Coefficientl°F Coefficient/°C
ASTM-IP Petroleum Measurement Tables (ASTM D 1250 IP 200) are used for volume corrections in commercial transactions.
Specific heat capacity of petroleum liquids between 0 and 205°C (32 and 400°F) having a relative density of 0.75 to 0.93 at 15W can be calculated within 2 to 4 percent of the experimental values from the following equations:
UOUID FUELS 9-11
l-
Swbolt viscositv. so Specific gravity
6O/WF (OAPI)
Max.
nematic viscosity. cStD Kil
l- Copper strip T Universal at 3WC
(lOOoF) Fur01 at SOT
(122°F) CW’F) M40”( 122°F)
Max.
(81)
&BP
At 36~C 104“F)
MUX.
2.1
3.4
24.6
58’
166
At 5ov
Min.
(42)
>92
t Min. Min.
(2-w
(>45)
Max.
(40)
WQ)
Min. 1.4
2.OC
5.6
z-26.4
Z-65
Max.
2.2
3.6
26.4’
65F
lQ4F
Min.
1.3
1.9c
5.5
124.0
Xi6
(32.6)
(45)
(>W
c-300)
(xm
0.6499 (35 min)
0.6762 (30 min)
No. 3
No. 3
0.5
0.5’
The thermal conductivity of liquid petroleum products is given in Fig. 9-6. Thermal-conductivity coefficients for asphalt and paraf- fin wax in their solid states are 0.17 and 0.23 W/(m.K) respectively for temperatures above 0°C (1.2 and 1.6 Btu/(h.fP)(“F/in)l
Fuel systems for No. 1 and No. 2 fuel oil are not heated. Systems for No. 6 fuel oil are usually designed to preheat the fuel to 32 to 49°C (90 to 120°F) to reduce viscosity for handling and to 74 to 93°C (165 to ZOOOF) to reduce viscosity further for proper atomi- zation. No. 5 fuel oil may also be heated. (See Table 9-9.) Steam or electric heating is employed as dictated by economics, climatic con- ditions, length of line, and frequency of use. (See Fig. 9-7.) Pressure- relief arrangements are recommended on sections of heated pipe lines when fuel could he inadvertently closed between valves. Fuel can expand several percent between 15 and 100% (59O and 212OF). Fuel-pump capacity exceeds burner capacity; excess flow recircu- lates through pressure-relief valves in the pump (for simple No. 2 fuel systems) or in the fuel header (for multiple-burner heavy-fuel systems).
purposes. Fuel passes through an air eliminator and mechanical meter when loaded into or dispensed from trucks. Larger transfers such BS pipe-line, barge, or tanker movements are measured by fuel depth and “strapping tables” (calibration tables) in tanks and vessels, but positive-displacement meters that are “proved” (calibrated) fre- quently are gaining acceptance. After an appropriate settling period, water in the tank bottom is measured with a plumb bob or stick smeared with water-detecting paste.
Receipts of tank-car quantities or larger are usually checked for gravity, appearance, and flash point to confirm product identification and absence of contamination.
Safe@ Comiderationr Design and location of storage tanks, vents, piping, and connections are specified by state fire marshals, Underwriters codes, and local ordinances. In NFPA 30, Flmmuble and CombuPtiMe Lkpguidp Code, 1977, published by National Fire Protection Association, Quincy, Massachusetts, liquid petroleum fuels are classified as follows for safety in handling:
Class I (Eammable) liquid has a flash point below 37.8”C (lOOoF) and a vapor pressure not exceeding 0.28 MPa at 37.8”C (40 Ibf/in* absolute at lOOoF).
Class IA includes those liquids having flash points below 22.8’C (73OF) and boiling points below 37.8’C (lOOoF).
CommerciDl Codderationr Fuels are sold in gallons and in multiples of the 42-gal barrel in the United States. Table 9-11 shows units used elsewhere. Transactions exceeding 5000 to 10,000 gal usu- ally involve volume corrections back to 15.6OC (60°F) for accounting
9-12 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
160000 I50000
150000 140000
E g 14oooo E >
: 130000 a
% i c
s c
Y 8
G r
a 130000 B
0. > 120000 ;
& i
z
:
P
120000
110000
110000
100000
100000 0 IO 20 30 40 50 60 70 a0 90 100
API qrs”lt”
FIG. 94 Heat of combustion of petroleum fuels. To convert British thermal units per U.S. gallon to kilojoules per cubic meter, multiply by 2.787 163 E+ 02
Class IB liquids have flash points below 22.8”C (73OF); boiling wints. at or above 37.8V (lOOoF).
Class IC includes those‘liquid; having flash points at or above 22.8’C (73OF) and below 37.8V (lOOoF).
Class II combustible liquids have flash points at or above 37.8OC (100°F) and below 60% (140OF).
Class IIIA combustible liquids have flash points at or above 60% (140°F) and below 93.4OC (ZOOoF).
Class IIIB liquids flash at or above 93.4% (ZOOOF). NFPA 30 details the design features and safe placement of han-
dling equipment for flammable and combustible liquids. Crude oils with flash points below 37.8% (lOOoF) have been used
in place of No. 6 fuel oil. Different pumps may be required because of low fuel viscosity. Handling precautions related to flammability are covered in Petroleum Safety Data Sheet PSD 2215, Crude Oil as Burner Fuel, American Petroleum Institute, Washington.
Nonpetroleum Liquid Fuels Table 9-12 shows typical data on liquid fuels from tar sands, oil shale, and coal.
Tar Sands Canadian tar sands are strip-mined and extracted with hot water to recover heavy oil (bitumen). The oil is processed into naphtha, kerosine, and gasoline fractions, which are hydro- treated, in addition to gas, which is recovered. Tar sands are being developed in Utah also
Oil S/&e Oil shale is nonporous rock containing organic kero- gen. Raw shale oil is extracted by pyrolysis in a surface retort, after mining, or in situ after “rubblizing” the rock with explosives. Pyrol- yEi= orncks the korogcn, yielding raw ahe& 4 high in nitrvt;cu, w.y- gen, and &fur.
Shale oil has been hydrotreated and refined in demonstration tests into relatively conventional fuels. Refining in petroleum facilities is possible, and blending with petroleum is most likely.
Coal-Detioed Fuels Liquid fuels derived from coal range from highly aromatic coal tars to liquids resembling petroleum. Raw liq- uids from different processes show variations that reflect the degree of hydrogenation achieved Also, the raw liquids can be further hydrogenated to refined products. Properties and cost depend on the degree of hydrogenation and the boiling range of the fraction selected. A proper batance between fuel upgrading and equipment n&&cation is essential for the most economical use of coal liquids in boilers, industrial furnaces, diesels, and stationary gas turbines.
Coal-tar fuels are high-boiling fractions of crude tar from pyrol- ysis in coke ovens and coal retorts. Grades range from free-flowing liquids to pulverizable pitch. Low in sulfur and ash, they contain hydrocarbons, phenols, and heterocyclic nitrogen and oxygen corn- pounds. Being more aromatic than petroleum fuels, they burn with a more luminous flame. From 15 to 205°C (60 to 400°F) properties include:
Specific heat capacity 1.47-1.67 kJ/(kg.OC) [0X1-0.40 Btu/ (lb.OF)]
See the monograph edited by W. H. Huxtable, Coal Tar Fuels (Association of Tar Distillers, London, 1961). Properties of hydroge- nated-coal liquids, largely unreported as yet, will no doubt fall between coal-tar fuel and petroleum.
The EDS, H-Coal, and SRC-II processes hydrogenate coal to yield hydrocarbon liquids. Distillates between 177 and 510°C (350 and 950°F) are low-sulfur liquids in the viscosity range of No. 2 to No. 5 fuel oil. Ash content ranges from nil to a few ppm. High-ash residuals are minor fractions, often to be consumed in process rather than marketed.
SASOL in South Africa is using coal gasification followed by syn- thesis to produce gasoline and diesel fuel (Fischer-Tropsch process). There are proposals in the United States to use the same gasification process to provide for the synthesis of methanol as a liquid fuel. Fer- mentation ethanol can be considered as a fuel supplement in coun- tries with sufficient land, sunshine, and water to grow food, feed, and fiber at surplus levels. With Bash points of 11 and 14°C (51.8 and 57.2OF) respectively, methanol and ethanol must be handled with due regard to tlammability
Coal-derived fuels are discussed in greater detail in a later subsection.
GASEOUS FUELS
Natural Gas Natural gas is a combustible gas that occurs in porous rock of the earth’s crust and is found with or near accumu- lations of crude oil. Being a gas, it may occur alone in separate res- ervoirs. More commonly, it forms a gas cap entrapped between petroleum and an impervious, capping rock layer in a petroleum res- ervoir. Under high-pressure conditions, it is mixed with or dissolved in crude oil.
.Natural gas consists of hydrocarbons with a very low boiling point. Methane is the main constituent, with a boiling point of -1540~ (-245’F). Ethane, with a boiling point of -89% (-128OF) may be present in amounts up to 10 percent; propane, with a boiling point up to -42°C (-44OF), up to 3 percent. Butane, pentane, hexane, heptane, and octane may also be present. Physical properties of these gases are given in Table 9-13.
Although there is no single composition that may be called “typi- cal” natural gas, Table 9-14 shows analyses of natural gas in 14 large cities in the United States.
Natural gas termed “dry” has less than 0.013 L of gasoline/m3 (0.1 gal/1000 fts). Above this amount, it is termed “wet.” The terms “wcat” and “wur” arc used IO denote rhe absence or presence of HsS.
FIG. 9-5 Viscosity-temperature relationships for typical petroleum fuels
Maximum viscosity
for pumping and handling
Steam atomization
Mechanical atomization
I I I I I I I I I I I I I, I I I
0 100 200 300
FIG. 9-6 Thermal conductivity of petroleum liquids.
- I.1
- 1.0
2 -0.9 2
o-
“= -0.8 5
;
2 -0.7
-0.6
d-II 100 250 300 350 400 450 c
I I I I I, I II I I I I I I I I I I,,,, I 400 500 600 700 800 F
9-13
9-14 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Dlophrogm rehef valve -
Pressure gouge ---+C
High-pressure supply line,
Pressure gauge ----_,_c
Shutoff valves
Duplicate pumps with mtegrol pressure-relief wives
Shutoff valves
Duplex oil filter------.
Check valve-.____
Suction line-----
Shutoff wlwe --.
Tank suction heater _ (not required for light oil)---
Oil-storage tank-
Supply and return lines far any number of branch circuits
Main-inlet shutoff valve far branch clrcult
- Low-oressure
t
return line
Far overhead
Traps
FIG. 9-7 Oil-storage tank and main circulating loop. (Combustion Handbmk. North American Mfg. Co., Ckwhnd, Ohfo &#uJS.)
TABLE 9-l I Commercial Units of Fuel Moaruromont
Customary unit Multiply by this factor ta get API-
preferred metric unit
Volume Cubic meter, m3 Cubic decimeter, dm’
m3 (264.2 U.S. gal) 1 1.000000E+@3 bbl (42 U.S. gal) 1.589 873 E - 01 Imperial gal (1.201 U.S. gal) 4.546092E-03 4.546092E+OO us. gal 3.785 412 E - 03 3.785 412 E + M) L (0.2642 U.S. gal) 1.000000E-03 Imperial qt (0.3002 U.S. gal) 1.13652.3E-03 :.136523E+00 U.S. qt (0.2.wO us. gal) 9.463 529 E -04 9.463 529 E - 01
UPU Kilazrem. kc Tonne. t*
Long (U.K.) tan (2240 lb) 1.016 047 E + 03 1.016 047 E + 00 Short (U.S.) ton (20~1 Ib)t O.O71847E+O2 0.071 847 E - 01 Metric ton (tonne; 2204.616 lb) 1.01I0 000 E + 03 1
‘Allowable (not official SI) unit. f Not commonly used far petroleum measurement.
The proven reserves of natural gas in the United States total about 210 trillion cubic feet. Production in 1977 was about 20 trillion cubic feet. This reserves-to-production ratio of 10.5 suggests that natural gas from conventional sources will be seriously depleted by the end of the 1980s. Unconventional natural sources, such as tight sands, Devonian shales, and geopressure zones, would increase natural-gas reserves significantly but at much higher costs. Surface coal gasifi- cation processes now being developed may provide substitute natural gas that is more economical than unconventional natural sources. The subsection dealing with coal gasification describes the technol- ogies for making low-, medium-, and high-Btu gas (substitute natural gas) currently being developed.
Liquefied Natural Gas (LNG) The advantages of storing and shippin natural gas in liquefied form derive from the fact that 0.03 ms (1 ft ) of liquid methane at - 162’C (-26O’F) equals about 18 m3 (630 fts) of gaseous methane. Temperatures higher than - 162OC can be used if the liquid is stored under pressure. For example, the liquid state is maintained at 22.4 bar (325 lbf/in*) and -103°C (-155OF). The critical temperature of methane is -82’C (- 116”F), and the corresponding critical pressure is 46.4 bar (673 Ibf/ ins). One ma(264 gal) weighs 412 kg (910 lb) at -164% (-263OF). The heating value is about 24 MJ/L (86,000 Btu/gal).
The heat of vaporization of LNG at 1 bar is about 300 J/m3 (10 Btu/standard fts). It requires 232 MJ to vaporise 1 m30f liquid meth- ane (6575 Btu/fta).
LNG is stored in metal double-wall or prestressed concrete tanks, frozen-earth storage, or mined quarries or caverns.
Liquefied Petroleum Gas (LPG) The term “liquefied petroleum gas” is applied to certain specific hydrocarbons which can be lique- fied under moderate pressure at normal temperatures but are gaseous under normal atmospheric conditions. The chief constituents of LPG are propane, propylene, butane, butylene, and isobutane, mixed in any proportion or with air. LPG produced in the separation of heav- ier or more dense hydrocarbons from natural gas is mainly of the paraffinic (saturated) series. LPG derived from oil-refinery gas may contain varying low amounts of olefinic (unsaturated) hydra carbons.
LPG is widely used for domestic service, supplied either in tanks or by pipe lines. It is also used to augment natural-gas deliveries on peak days and by some industries as a standby fuel.
&formed Gas Although applicable to any gas transformed by suitable treatment, the term “re-formed” is ordinarily applied to lower-thermal-value gases obtained by the pyrolysis and steam decomposition of high-thermal-value gases such as natural gas, pro- pane, butane, or refinery oil gas. It is sometimes used to meet peak- load requirements.
Oil Gases These gases, with heating values from 30 to 41 MJ/ m3 (300 to 1100 Btu/fts), are made by thermal decomposition of oils ranging from naphtha to heavy-residuum high-carbon oils. Although of minor importance now in many countries, the lower-Btu gases were distributed as manufactured gas by certain utilities, whereas the high-Btu gases were used primarily to supplement peak-load requirements by companies serving natural gas.
Producer Gas This gas is generated by blasting a deep, hot bed of coal or coke continuously with a mixture of air and steam. The products of the process are CO, Ns (from the use of air), small amounts of Hz, and some COI. Because of the large percentage of nitrogen in the gas, to 150 Btu/fts)].
the heating value is low [4.4 to 5.3 MJ/ms (125
Blue Water Gas, Carbureted Water Gas, and Coal Gas These are combustible gases produced from coal or coke (in some cases enriched with oil, natural gas, or LPG) which have continuously declined in use in recent years to an extremely small share of the market.
Blast-Furnace Gas This gas is a by-product in the manufacture of pig iron in blast furnaces and is generally used for heating pur- poses within the plant. The heating value, approximately 3.2 MJ/m’ (90 Btu/fts), is too low for sale to others.
Acetylene Acetylene is used primarily in operations requiring high flame temperature, such as welding and metal cutting. In order
TABLE 9-12 Chamctwisks of Typical Nonpholeum Fuels
Conventional coal-tar fuels from Typical coal-derived fuels with different levels of retortine hydrogenationb
8.1 8.9 8.0 3.1-3.4 5w30 3.6 At 38OC At 38’C At 38’%
86.0 9.1
3.6-4.3 0.9-1.1 (0.2 <O.OOl
9.4
89.1 87.8 7.5 9.7
1.4-1.8 2.4 1.2-1.4 0.6
o'4io'5 0.07
11.9 9.1 8.9 8.0 6.2 6.9
175-400 0.9607 8.0
89.6 10.1 0.3 0.04 0.004
12.5-495 0.914 0.817 0.864 7.6 6.8 7.2 2.18
At 38°C
89.0 86.1 87.1 11.1 13.84 12.69 0.5 0.12 0.04
0.09 0.01 0.07 0.04 0.02 0.10
‘CTF 50, 100, etc., indicate approximate preheat temperature, OF, for atomisation of fuel in burners (terminology used in British Standard B.S. 1469) bPmperties depend on distillation range, as shown, and to a lesser extent on coal source. ‘Using recycle-solvent process. dTar sands, although a form of petroleum, are included in this table for comparison. ‘Inorganic mineral constituents of coal tar fuel:
5 to 50 ppm: Ca, Fe, Pb, Zn (Na. in tar treated with soda ash) 0.05 to 5 ppm: Al, Bi. Cu, Mg, Mn. K. Si, Na, Sn Less than 0.05 ppm: As, B, Cr. Ge. Ti. V, MO Not detected: Sb. Ba. Be, Cd, Co, Ni, Sr, W, Zr
‘Inherent ash is “trace” or “<O.l%,” although entrainment in distillation has given values as high as 0.03 to 0.1%.
TABLE 9.13 Physical Properties of light Hydrocarbona’
At 33T .......................................... AtmF.. ....................................... AtWF.. ........................................ At IWF ......................................... At IWF.. At I3O.F
‘Johnson and Auth (eds.), Fuels and Combwth Handbook, McGraw-Hill, New York, 1951. To convert British thermal units per cubic foot to megajoules per cubic meter, multiply by 0.0373; to convert British thermal units per pound to megajoules per kilogram, multiply by 0.00232; to convert British thermal units per gallon to megapules per cubic meter, multiply by 0.277; and to convert cubic feet to cubic meters, multiply by 0.0283. Cnl/(lb~mol)(at 60°F) X 0.008 = ma/ (kg.mol)(at 1fYC).
tIdeal gas = 379.5 ft3. tApparent values for dtssolved methane at 60°F. @ased on “perfect gas.”
9-15
9-16 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Baltimore, Md. Birmineham. Ala. Boston,vMass. Columbus, Ohio : : : : Dallas, Texas Houston. Texas Kansas City, MO. Los Angeles, Calif. Milwaukee, Wis. New York, N.Y. Phoenix, Ariz. Salt Lake City, Utah : San Francisco, Calif. WashIngton, D.C.. :
__ . . _ neproauced by permission tram “Gas Engineers Handbook,” American Gas Association, Industrial Press, New Yorl f Average analyses (1954 data) obtained from the operating utility company(s) supplying the city. The gas supply may vary considerably from these data-
especially where nwxe than one pipe line supplies the city. Also, as new supplies may be received from other sources, the analyses may change. Peak shaving (if used) is not accounted for in these data.
NOTE: TO convert British thermal units per cubic foot to megajoules per cubic meter, multiply by 0.0373.
to transport acetylene, it is dissolved in acetone under pressure and drawn into small containers which are filled with porous material.
Hydrogen Used primarily in the production of ammonia and chemicals, in the hydrogenation of fats and oils, and as an oven reducing atmosphere, hydrogen is limited as a fuel to certain special industrial purposes such as cutting and welding. It is made industri- ally by electrolysis of water, by thermal cracking of natural gas and other hydrocarbons, and by the steam-re-forming reaction. Hydro- gen as a nonpolluting fuel gas has been getting considerable attention.
Sulfur Impurities Most natural gas is free from sulfur com- pounds; however, some wells deliver gas containing levels of hydro- gen sulfide and sulfur which must be removed before delivery. Pipe-line-company purchase contracts specify maximum limits of impurities; actual HIS and sulfur (after purification) seldom exceed 0.002 and 0.02 g/m3 (0.1 and 1.0 gr/lOO fta) respectively.
Hydrogen sulfide in manufactured gases may range from approx- imately 2.30 g/m3 (100 gr/lOO ft3) in blue and carbureted water gas to several hundred grains in coal and coke-oven gases. Another important sulfur impurity is carbon disulfide, which may be present in amounts varying from 0.007 to 0.07 percent by volume. Smaller amounts of carbon oxysulfide, mercaptans, and thiophene may be found. However, most of the impurities are removed during the purification process and either do not exist in the finished product or are present in only trace amounts.
Supercompressibility of Natural Gas All gases deviate from the simple gas laws to a varying extent. This deviation is called “super- compressibility” and must be taken into account in gas measure- ment, particularly at high line pressure. For example, since natural gas is more compressible under high pressure at ordinary tempera- tures than is called for by Boyle’s law, gas purchased at an elevated pressure gives a greater volume when the pressure is reduced than it would if the gas were ideal.
The supercompressibility factor may be expressed as follows:
2 = (RT/PV)Os
where Z = supercompressibility factor A = universal gas constant T = gas temperature, absolute P = gas pressure, absolute V = molar gas volume
For determining supercompressibility factors of natural-gas mix- tures, see A.G.A. Manual for the Determination of Supercompres- s&t&y Factors for Natural Gas, American Gas Association, New York, 1963; and A.G.A. Gas Measurement Committee Report No. 3, 1969.
FUEL AND ENERGY COSTS
Fuel costs vary widely from one area to another because of the cost of the fuel itself and the cost of transportation. Any meaningful cost comparison between fuels would require current costs based on the amounts used at a particular geographical location, utilization effi- ciencies or energy-ratio data for the equipment involved, the effects of “form value,” etc. Although the costs given in Table 9-15 will not apply to specific locations, they do give fuel-cost trends.
Figures 9-8 and 9-9 are charts for comparing fuel and energy costs.
COAL CONVERSION TO LIQUID AND GASROUS FUELS AND FEEDSTOCKS FOR THE CHEMICAL-PROCESS INDUSTRIES
Converting coal to environmentally acceptable synthetic gaseous and liquid hydrocarbons would supplement the dwindling reserves of petroleum and natural gas of the United States and help reduce national dependence on imported fuels.
Coal gasification yields a wide variety of useful products for the residential, utility, and industrial markets. A medium-Btu gas (MBG), produced by gasifying coal with oxygen and steam, can be upgraded to substitute natural gas (SNG) for distribution in existing natural-gas pipe lines, or MBG can be used for firing boilers and kilns and as a feedstock for the catalytic synthesis of chemicals. A 1owBtu gas (LBG), produced by gasifying coal with air and steam, can be used close to gasifier sites to fire boilers, kilns, and several other industrial processes that now depend on petroleum and natural gas.
Coal liquefaction, effected by hydrogenating coal at high temper- ature and pressure, yields low-ash, low-sulfur boiler fuels for electric
TABLE 9-15 Time-Price Relationships for Fossil Fuels’
SOURCE: MIneral Facts and Problems, U.S. Bur. Mines Bull. 667, 1975. ‘All average annual prices f 1974.
I 20
10
A
I’Z
Y
FIG. 9-O Comparing power-plant fuel costs. The difference in fuel costs between alternative generating plants is found easily with the nomograph. Knowing fuel costs in cents per million British thermal units and plant heat rates in British thermal units-per kilowatthour makes it possible to find a fuel- cost differential factor in dollars ner hour-megawatt. This number. when mul- tiplied by unit output in rnega&tts and unit &rating hours, gives the differ- ential fuel cast in dollars. (Courtesy Power.)
power generation, process heating, and making high-grade fuels such as gasoline and chemical feedstocks. Coal pyrolysis, or thermal decomposition, and the catalytic hydrogenation of carbon monoxide (from coal gasification) are also sources of liquid fuels and chemical feedstocks.
Bodle, Vyas, and Talwalker (Clean Fuels from Coal Symposium II, Institute of Gas Technology, Chicago, 1975) presented the chart in Fig. 9-10, which shows very simply the different routes from coal to clean gases and liquids.
Coal gasification and liquefaction are old technologies; current research, development, and demonstration efforts are aimed toward technical and economic improvements in some of the old, or first- generation, technologies and toward seeking new ways to accomplish the same ends: cheap and “clean” coal-conversion processes.
COAL GASIFICATION
CEN~~LREFEREN~E~: Fuel Cmtjicaffm, symposium sponsored by American Chemical Society, 157d meeting, Sept. 12-13, 1966. Von Fredersdorff and Elliott, Chemfstry of Coal Uttltzatia, suppl. vol., ed by H. H. Lowry. Wiley, New York, 1963. ChemLstry of Cwl Uttliurtbn, 2d suppl. vol., ed by M.A. Elliott, Wiley, New York, 1981.
Background Converting coal to combustible gas has been prac- ticed commercially since early in the nineteenth century. The first gas-producing companies were chartered in 1812 in England and 1816 in the United States to produce gas for illumination by the heat- ing or pyrolysis of coal. This method of producing gas is still in use as a by-product of the carbonixation of coal to produce coke for met- allurgical purposes. The advantages of a gaseous fuel as a source of heat and power increased the use of coal for gas generation. The gas producer, in which a downward-moving bed of coal or coke is reacted with air and steam, was extensively used to prepare a gas of relatively low thermal content per unit volume, 3.7 to 6.0 MJ/ms.
The development of the cyclic water-gas process in 1873 permit- ted the continuous production of gas of higher thermal content, II.2 to 13.0 MJ/m? By adding oil to the reactor, the thermal content of
COAL GASIFICATION 9-17
the gas was increased to from 18.6 to 20.5 MJ/ms. This type of gas, carbureted water gas, was distributed in urban areas of the United States as a fuel gas for residential and commercial uses until its dis- placement by lower-cost natural gas began in the 1940s. At approx- imately that time, development of oxygen-based gasification pro- cesses was initiated in both the United States and other countries. An early gasification process developed by Lurgi Kohle u Mineralijltech- nik GmbH at that time, which operated at elevated pressure, is still in use, as are many producer-gas systems. Table 9-16 lists the com- position of the coal-derived gases produced by these methods.
Theoretical Considerations The chemistry of coal gasification can be depicted by conveniently assuming coal as carbon and by list- ing the several well-known reactions involved; see Table 9-17. Reac- tion (g-13) is the combustion of carbon and oxygen, which is highly exothermic. This reaction supplies most of the thermal energy for the gasification process. The oxygen may be used as pure oxygen or be contained in air. Reactions (g-15) and (9-16) are endothermic and represent the conversion of carbon to combustible gases. These are driven by the heat energy supplied by Reaction (9-13).
As hydrogen and carbon monoxide are produced by the gasifica- tion reaction, these gases react with each other and with carbon. The reaction of hydrogen with carbon as shown in Reaction (9-14) is exo- thermic and can contribute heat energy. Similarly, the methanation reaction (9-18) can contribute heat energy to the gasification. These equations are interrelated by the water-gas-shift reaction (g-17), the equilibrium of which controls the extent of Reactions (9-15) and (9- 16).
It has been shown by several authors (cf. Gumz, Gas Producers and Bkast Furnaces, Wiley, New York, 1950; and chapter on gasifi- cation by Elliott and van Fredersdorff, Chemistry of Coal Utlkae- tion, suppl. vol., ed by Lowry, Wiley, New York, 1965) that all the reactions could be based on three fundamental reactions: the Bou- douard reaction (g-16), the heterogeneous water-gas reaction (g-15), and the equation for methane formation by the hydrogasification reaction (9-14). The equilibrium constants for these reactions are suf- ficient to calculate all the reactions listed.
It is not possible to calculate accurately actual gas composition by using the relationships of Reactions (9-13) to (9-18) in Table 9-17. Since the gasification of coal always takes place at elevated temper- atures, thermal decomposition, or pyrolysis, takes place as coal enters the gasification reactor and is exposed to these temperatures. Reac- tion (9-19) treats coal as a compound of carbon and hydrogen and postulates its thermal disintegration to produce carbon (coke) and methane. Reaction (9-20) assumes the stoichiometry of hydrogasify- ing part of the carbon to produce methane and carbon. These reac- tions as well as those involving the other elemental constituents of coal take place during gasification.
It is possible to utilize these reactions and their relationships with each other for predicting the effects of changes in the operating parameters of gasification. At higher temperatures, endothermic reactions are favored at the expense of exothermic reactions. We can expect a decrease in methane production as Reactions (9-14) and (9- 18) will proceed at a lower rate, CO production will be favored, and all reaction rates will increase in the direction in which heat absorp tion takes place. An increase in pressure will favor those reactions in which a smaller number of moles (or volumes) is formed At higher pressures, production of COs will be favored as well as that of meth- ane. The knowledge of stoichiometry, equilibrium conditions, and rates for these gasification reactions provides a sound basis for mod- cling and extrapolating gasification systems.
A great deal depends on the gasifier system, coal reactivity and particle size, and method of contacting coal with gaseous reactants (steam and air or oxygen). It is generally believed that oxygen reacts completely in very short distances from the point at which it is mixed or comes in contact with coal or char. The heat evolved acts to pyrolyze the coal, and the char formed will then react with carbon dioxide, steam, or other gases formed by the combustion and pyrol- ysis of coal and char. The assumption made in Table 9-17 that the solid reactant is carbon is probably close to being correct. The con- version of coal to char and the type of char formed affect the kinetics of gas-solid reactions. While the reaction rate does vary with tem-
‘To convert British thermal units per gallon to kilograms per cubic meter, multiply by 2’78.7; to convert British thermal units per cubic foot to kilojades per cubic meter, multiply by 37.3; to convert British thermal units per pound to kilojoules per kilogram, multiply by 2.326; and to cunvert British thermal units per kilowatthour to kilojo& per kilowatthour, multiply by 1.055.
FIG. 9-10 The production of clean fuels from coal. (Boaed on W. &d&z, K. VYOJ, and A. Tdudker, Clean Fuels from Coal Symposium II, Institute of Gas Technology, Chicago, 1975.)
perature as in all chemical reactions, the overall rate of reaction is controlled probably by the chemical reaction rate below 1000°C (1832°F). Above this, pore diffusion has an overriding effect, and at very high temperatures surface-film diffusion probably controls. Thus, for many gasification processes the reactivity of the char is quite important. This may depend not only on parent-coal charac- teristics but also on the method of heating, rate of heating, and par- ticle-gas dynamics.
The importance of these concepts can be illustrated by the extent
TABLE 9- 16 Rq2wi.s of coocDwiied Gas.8
Reactant system
Andysis, volume 46’ Carbon monoxide, CO Hydrogen, Hp Methane, CH, Carbon dioxide, CO2 Nitrogen, Np Othert
Fuel value. hlJ/ms (Btu/
Clea” I gaseous
fuels
Coke-oven gas Producer gas Water gas
Carbureted water Synthetic coal b3.s %-
Pyrolysis
Clean hqwd fuels
to which the pyrolysis reactions contribute to gas production. In a moving-bed gasifier (e.g., producer-gas gasifier), the particle is heated through several distinct zones of carbonization, char devola- tilization, char gasification, and fixed-carbon combustion. As much as 15 to 17 percent of total gas production is liberated in the coal carbonization, almost 2.3 percent may be produced by char devola- tilization, and some 60 percent is generated by actual gasification of the remaining char. This emphasizes the importance of coal quality or reactivity.
Types of Available Gasification Equipment The fundamental chemistry and physics of gasification motivate the design of existing and advanced gasifiers. The equations listed in Table 9-17 show that a logical means of contacting a solid particle with a gaseous reactant is necessary, that the transfer of heat within the gasifier (and to the gasifier) is a critical parameter, and that variations in pressure and temperature alter the composition of the gas produced. In addition, the type of coal and the composition of both organic and inorganic constituents have a strong influence on gas composition and applicability of various gasification systems. Several gasification
Moving bed
Fluidized bad
Coat m Gas
o-5mm
Residual char ’
Entrained suspension
Ash
FIG. 9-11 Coal-gasification systems
L
Ash Temperature oC
Gas
Gas
90 m MO
Temperature oC :
Ash
Coal ,
systems designed for contacting particles of coal with gaseous reactants at temperatures above 700°C (1292°F) are shown in Figure 9-11.
The three main types of reactors shown in Figure 9-11 are in actual commercial use: the moving bed (often referred to as a “fixed” bed), the fluid&d bed, and the entrained or suspension flow reactor. These differ in size consist of coal fed, reactant and product flow, residence time, and reaction temperatures.
Moving-Bed Reactorr This type of gasifier was one of the ear- liest used. It requires a coal particle size of 2 to 50 mm and is com- mercially used with air or oxygen. Steam and oxygen (air) are intro- duced, and ashes leave at the bottom of the reactor; coal is fed, and product gases leave at the top. The low temperature differentials between incoming and outgoing flows indicate the efficient transfer of heat between gaseous and solid reactants and products. Notewor- thy is the relatively low temperature of product-gas effluent, which for some coals is below 500% (932’F). This low temperature results in a minimum of energy contained as sensible heat in the product gases with a resultant decrease in oxygen usage and an improved thermal efficiency.
The countercurrent Bow, low exit-gas temperature, and use of a mechanical grate at the bottom of these moving-bed systems cause some disadvantages. To protect the grate, steam in greater quantity than required for reaction is injected to reduce the bottom temper- ature. This impresses a negative thermal input and reduces overall efficiency. The coal as it enters is subject to pyrolysis as it passes down the gasifier, and tars and oils which must be recovered and/or uti- lized are produced. The resultant mixture of organic liquids and water condensate must be separated and the water purified prior to discharge. Finally, the need to dispose of the portion of the run-of- mine coal which is too fine to be used for feed can be an economic burden.
Reasonable procedures are available for meeting some of these prnhlemP Snnme nf thrrp ~~~rr,=ntly Ling ~atili?~J in nthe7 ,vwntries
may require modification to meet Environmental conditions in the United States. Considerable progress has been made toward this end by the Lurgi Kohle u Mineralijltechnik GmbH for their Lurgi gasi- fier. While many moving-bed gasifiers are available, the Lurgi is cur- rently the only gasifier that is commercially available for operation at elevated pressure. Units are routinely being operated at pressures of 30 bar (450 psig). An outline sketch of the pressurized Lurgi gas- ifier is shown in Fig. 9-12. Also shown is the outline of the first step in purifying the gas: a multiple-venturi water scrubber.
The maximum reactor size for the Lurgi gasifier is currently 3.9 m (12.8 ft) in internal diameter. The capacity of this size of gasifier depends on coal quality and has been able to handle approximately 750-GJ coal input/h, equivalent to more than 25,ooO kg/h (55,115 lb/h) of coal or 70,000 m3/h (245,700 ft3/h) of gas production. While stirrers have been designed to break up agglomerates so that caking coals can be handled, limited commercial experience is available with such coals.
COAL GASIFICATION 9-2 1
Crude gas
Ash
FIG. 9-12 Lurgi gas&r.
Fluidized-Bed Reactors The commercial gasification of coal with oxygen (air) and steam began with the use of a tluidized-bed reactor developed by Winkler (German Patent 437,970, filed Sept. 28, 1922). The coal is usually ground to sizes below 8 mm (%s in), which allows the entire run-of-mine coal output to be utilized. In contrast to the moving-bed reactor, the iluidized-bed reactor is essen- tially a completely mixed, partially cocurrent reactor. In the Winkler generator, coal is injected into the fluidized bed and the reactant gases are injected at two levels in the iluidized bed to maximize car- bon conversion. The present commercial units are operated at essen- tially atmospheric pressure and are used primarily with reactive coal or with chars derived from lignite carbonisation. Figure 9-13 shows an outline sketch of a Winkler gasifier.
The fluidized-bed reactor normally operates at higher tempera- tures than the moving-bed reactor and, being a completely mixed system, results in a higher outlet-gas temperature. This reduces effi- ciency but does destroy tars and oils and reduces the water-contam- ination problem. The major problem in any fluidized-bed system is the extent of carbon conversion and the carry-over of fine particles from the reactor. Normally, this carry-over has a high carbon content and must be collected and used for boiler fuel to avoid economic losses. The gasifiers currently in commercial use have internal diam- eters in excess of 4 m and are 20 m in height. Production of more than 50,000 ms/h of gas is achieved by the Winkler gasifier (equiv- alent to 540 CJ/h or 18,000 kg/h of bituminous coal) even though the gasifier is operated at atmospheric pressure.
Condenrate
Steam and oxygen
Prccerr steam
Ash
FIG. 9-13 Winkler gasifier
The Winkler gasifier cannot handle agglomerating coals, as the formation of such agglomerates would disrupt the uniformity of the fluidized bed Similarly, coals containing ash of low fusion tempera- ture could cause difficulties by forming ash agglomerates. Efforts in solving these problems and increasing operating pressure are being actively pursued.
Entrained or Suspension Gasification Entrained gasification in the Koppers-Totzek gasifier, shown in Fig. 9-14, takes place at temperatures close to 15OO“C (2732OF), using fine particles of coal at short residence times. The process is cocurrent with coal particles entrained in the turbulent reactant gases. The Koppers-Totzek pro cess, currently operated at atmospheric pressure, is the most widely utilized commercial example of entrained gasification. More than 50
FIG. 9-14 Koppers-To&k gas&r.
9-22 ENERGY UtlUZATION, CONVERSION, AND RESOURCE CONSERVATION
gasifien of this type have been built, mostly for producing ammonia- synthesis gas.
Because of the short reaction time, usually only a few seconds, coal particles are very rapidly devolatilized and lose any inherent char- acteristics of the original coal. All types of coal can be handled in Koppers-To&k gasifiers. The high operating temperature effec- tively gasifies all hydrocarbons, tars, or phenolics which may be formed during gasification. This reduces gas-purification and water- condensate-handling problems.
Pulverized coal (90 percent less than 200-mesh) is screw-fed from hoppers to burners in which oxygen and steam convey coal at veloc- ities in excess of flame-propagation rates into the gasifier. The tem- perature at the burner nozzles may reach 1900°C (3452OF). Gas temperatures at the reactor exit may be close to 1500°C (2732OF). At these high temperatures, the mineral content of the coal is in mol- ten form, and part of it is removed from the gasifier as a slag or melt. Part of the ash is carried overhead in particulate form and is removed in water scrubbers. While the Koppers-Totzek type of gas- ifier can handle all types of coal, careful attention must be paid to ash characteristics. Generally, one can characterize two general classes of slags produced from coal ash: a “short” slag, in which the temperature differential between softening and flow point is small; and “long” slags, in which this temperature differential is large and there are phases of sintering, clinker formation, softening, and finally flowing. The short slags are ideally suited for high-temperature entrained gasification. In addition to this general description, there are important criteria of slag viscosity. This should be less than 2.5 Pa.s (250 P) for suitable drainage of slag from powdered-fuel-slag- ging systems operating at atmospheric pressure. The slag chemistry is also critical, as high-silica slags present problems of both high vis- cosity and the potential of silica vaporization at temperatures of 1650°C (3362OF). [For detailed data on slag behavior and charac- terizations, see Hoy, Roberts, and Wilkins, Inst. Gas Eng. J., 444- 469 (June 1965)].
The entrained gasifier offers many advantages: the ability to han- dle a wide variety of coals, the elimination of tar and oil formation, and a conveniently disposable water-condensate and solid residue. The latter is generally free of carbonaceous matter and low in leach- ability. There are problems of handling high temperatures, refrac-
tory life, and slag control. The rapid reaction rate requires good con- trol to prevent an exces of oxygen should the coal feed be interrupted. There is no reservoir of carbon, as is available in either the moving- or the fluidized-bed reactors. Operation at atmospheric pressure is a handicap, and considerable development effort is in progress to provide a pressurized system. Present capacity at atmo spheric pressure can reach 360 GJ/h (360 X lo6 Btu/h) per gasifier, equivalent to 13,000 kg/h (28,660 lb/h) of bituminous coal for the two-headed gasifier shown in Fig. 9-14. Recent development and commercial adaptation of a four-headed unit have doubled these throughputs.
Development and Utilization Both government and industry are sponsoring large development programs aimed at alleviating the various disadvantages of presently available commercial gasifiers. These programs involve all types of gasifiers and have as major objec- tives increased operating pressures, reduced reactant consumption, decreased capital costs, and improved product quality. Many of these developments have reached the pilot-plant stage and appear to jus- tify commercial consideration. Table 9-18 lists several commercial and developmental gasification systems. The data are all based on 100 kg (2205 lb) of moisture-and-ash-free (maf) coal.
The two moving-bed systems shown have essentially the same reactor configuration except that the BG/Lurgi unit eliminates the grate, utilizing a slagging bottom with a large reduction in steam input. This raises the average temperature and increases throughput. The critical difference is the reduction in specific steam consumption (kg steam/kg coal gasified) by a factor of almost 5. This reduces unreacted steam in the gasifier and thereby the total gas volume, which in turn reduces solids carry-over and gas-handling costs down- stream from the gasifier. The lower steam input results in a reduced Hs/CO ratio and reduced CH, and COs concentration in the product gas. Carbon conversions are similar for both moving-bed units. The problems of tars and oils are also similar, but progress has been made in recycling heavy tars and contained fines back to the gasifier.
The effect of increasing pressure is shown dramatically by com- paring the two fluidized-bed gasifiers in Table 9-18. The HYGAS unit operates at much higher pressures and, by using staged fluid&d beds, achieves a low gas-exit temperature. The result is a large decrease in specific oxygen consumption (kg oxygen/kg coal gasi-
TABLE 9-18 Commmial and Dwolopmontal GasiioGon Processes, Oxy~wwBbwn Reactant Consumption, and Gas Production
Gas exit temperature, OC Pressure. bar Feed capacity, GJ/(h.gasifier) Reactants and
Oxygen, nM products per 1000 kg -lb
Oxygen, kg Steam, kg Dry raw product gas, nMs
Gas analysis, volume 96 Carbon dioxide, COs Carbon monoxide, COP Hydrogen, Hs Methane. CIC Otherd _ Fuel value, MJ/nM’
H&O, volume ratio Product utilization
Equivalent synthesis gas,’ nMs/lOOO kg coal
Equivalent SNG. (CH&’ nMs/lO@l kg c!clal
560 30
750
247 337 490 352 461 700
1336 275 516 2050 1744 1900
29.7 2.5 16.9 60.6 39.1 27.8 11.3 7.6
1.0 1.5 12.3 14.2 2.1 0.46
20.0 34.0 41.0 3.0 2.0
10.7 1.21
1596
413
440 20
2100
1939
517
700 340 1290 atm 70 atm 600 6900 380
213 304 684
587 638 300
1642 2016
24.7 24.0 30.5 19.4
1.4 14.5
1.27
71 56.7 32 8
1.4 11.6 0.56
1850 1645
542 462
1290 40
410
657 953
.C 2136
10.6 51.6 35.1
0.1 2.6
11.1 0.68
1966
470
‘pilot Plants are of various sizes: BC/Lurgi. 12,ooO kg/h; HYCAS, 2500 kg/h; -rexam, E@O kg/h. bu on moisture-and-ash-free (maf) coal with fuel value approximatelv 30 G[/lOOO kc. ‘Texaco feeds coal slurried with water (60% coal); no other st&m added’ . _ dIncludes nitroaen and various imourities (Ha. COS. NH*. etc.). ‘Synthes_is gas &uned equal to &n of Hs: dd, and h X ?Hi &entration. ‘Methane potential assumed equal to methane (CH,) concentration plus % (Hs + CO) concentration
COAL GASIFICATION 9-23
fied). The much higher pressure favors methane production and a higher COs level in exit gas. The results shown for the developmental HYGAS processes are tentative; additional operation to confirm them is required. Winkler is operating a single-stage tluidized-bed pilot plant at pressures up to 10 bar.
While elevated pressure will decrease compression costs (oxygen volumes are one-fourth or less of the volume of product gas), carbon conversion is not appreciably improved. The HYGAS process, by uti- lizing several fluid&d beds, does achieve some improvement. Two processes, Westinghouse and U gas, report succes in agglomerating the ash particles by allowing higher temperature at the bottom of the bed. The low-carbon agglomerates are discharged preferentially owing to their larger size. Several processes utilize the high heat- transfer capability and solids mobility to supply external heat to the gasification reaction. The COs acceptor process uses the exothermic absorption of COs by calcined limestone or dolomite to supply heat for the steam-carbon reaction. Pilot-plant tests have demonstrated technical feasibility but not economic viability. The COGAS process supplies heat by burning part of the char externally with air and recycling the hot char to the steam-carbon reactor. The use of nuclear heat has been suggested in Germany, where high-cost coal could be saved by this means. All processes operated without the use of oxygen can effect a saving since the oxygen plant is of an order of magnitude of capital cost similar to that of the gasification system. However, these processes cannot be considered as operational in the commercial sense.
Operation at elevated pressure can benefit the performance of an entrained-flow gasifier by reducing compression cost. KruppKop- pers, the parent firm supplying the Koppers-Totzek gasifier, has joined with Shell Oil to develop a pressurized version. This version should provide a gasifier of higher throughput and gas production at a lower cost primarily through a reduction of compression cost. In Table 9-18 data are provided for a pressurized Texaco unit. Both atmospheric and pressurized entrained-tlow gasifiers have an exit-gas temperature above 1250°C (2282”F), and this results in a high oxy- gen requirement. Efficient heat recovery and utilisation of thermal energy in the gas&r exit gases are mandatory for recovery of the energy required for oxygen production and gas compression.
For elevated-oressure oneration of entrained-flow easifiers. a reli- - able coal-feed system is a ‘critical requirement. No carbon inventory in rhr msifkr ip avnilnhlr tn ~vnid hirrh nxvw=n mnrentrationc if rnal feed is-interrupted. The Texaco ga&er I& a pumped coal-water- slurry feed. The water content of such a slurry must be minimized to avoid high thermal penalties. The higher oxygen usage due to evaporating the water of a 65 percent coal-water slurry may be noted in Table 9-18 when the Texaco results are compared with those of Koppers-Totzek.
The use of coal-derived gases as a fuel is a well-known technique, but other important uses of such gases are addressed in Table 9-18. Conversion of raw product gas to a synthesis gas by re-forming its methane content is calculated for each of the processes. Similarly, conversion of product gas to methane is estimated by adjusting the hydrogen-tecarbon-monoxide ratio by the water-gas-shift reaction followed by methanation. Those processes which produce high meth- ane concentration in the raw product gas are best suited for produc- ing synthetic natural gas or methane (see HYGAS data).
For such conversions, the ratio of hydrogen to carbon monoxide is an important factor, and this ratio is listed for each process. The pro- cesses using high temperatures and low steam-to-coal ratios produce a gas rich in carbon monoxide. For producing hydrogen or hydrc- gen-rich synthesis gases, the carbon monoxide may be reacted with steam in a catalytic reactor external to the gasifier. The added steam must be considered in any overall evaluation of a gasification process. For example, if a hydrogen-to-carbon monoxide ratio of 2 is required in using a BG/Lurgi gasifier, an additional 437 kg (961 lb) of steam would be required for converting carbon monoxide to hydrogen. This would increase total steam consumption from 275 to 712 kg/ 1000 kg coal (0.275 to 0.712 lb/lb coal). While this would still be less steam than required by the Lurgi grate-type gasifier, the advantage of dependence on product-gas requirements is an important factor to be considered.
For this reason, any attempt to calculate the efficiency of gasifi- cation should be related to final product requirements and plant design. All the data are available in Table 9-18 to calculate the heat- ing value of products and relate them to the energy input in the 1000 kg of coal used as a basis. However, use of the crude product gas as a final product can be misleading, as shown by the added steam required for producing a 2: 1 synthesis gas. In addition, the energy used in the actual process must be considered, and this will depend on the use of waste heat to produce steam, power, or other needed energy forms for process use Also given in Table 9-18 is an estimate of the possible coal throughput for a single gasifier of each type. The commercial extrapolations for coal throughput for pilot-plant pro- cesse.s are based on published data. The process proponents have shown varying optimism.
The oxygen-blown gasifiers shown in Table 9-18 are probably of greatest industrial interest. In addition to producing a fuel gas undi- luted by nitrogen, they offer a potential of supplying synthesis gas for chemical use and synthetic natural gas (SNG) for pipe-line trans- port, which extends the marketability of oxygen-blown gasification systems.
In some cases, air-blown gasifiers may offer an advantage when fuel gas is desired. The use of air as a reactant does eliminate the capital cost and power required for operating an oxygen plant. This saving is negated to some extent by the need to purify larger volumes of product gas diluted with nitrogen. The lower fuel value of these product gases prevents economical pipe-line transport and mandates use of the fuel gases close to the point of production. Some estimates do show a 10 to 15 percent lower cost per unit of heating value for the products of air-blown gasification versus oxygen-blown product gases. Data are provided for two air-blown systems in Table 9-19. The gases produced are similar in characteristics to the producer gas shown in Table 9-16.
This table can be conveniently compared with Table 9-18, so that downstream gas volumes and purification-unit sizes can be estimated and compared for oxygen- and air-blown gasifiers. Owing to the use of air, larger volumes of lower-fuel-content product gas are obtained. As in the case of oxygen systems, a higher gas exit temperature requires more air usage and results in a lower fuel value. It should be noted that the Combustion Engineering gasifier shown in Table 9-19 is not a commercial system, but the data are based on pilot-plant nperatinn which has heen ex~rarmlated to a commercial siw. In an attempt to improve the heat recovery of the high-temperature-gasi- fier product, the Combustion Engineering gasifier injects coal feed
TABLE 9-19 Commwcial and Dovolopmontal Gasifiws; Ai-Rbwn- Roactont Consumption and Gas Production
Moving bed Lllrgi,
Entrained flow, Combustion
grate-type; Engineering; commercial Dibt Dht’
Gas exit temperature, OC 535 927 Pressure, bar 20 atm Feed capacity, CJ/h/gasifier 750 2700 Reactants and products per 1006
kg malt Air, nMs 1920 3561 Air, kg 2560 4880 Steam. kg 1650 Non.? Dry, raw product gas, nM3 2695 5322
‘Pilot plant has capacity of 4500 kg/h of COPI. tBsed on moisture-and-ash-free (maf) coal with a fuel value of 30 GJ/1000
/ kg. tlncludes sane hydrocarbons, moisture, and sulfur compounds.
9-24 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
into these hot gases to enrich the product gas through pyrolysis of the coal.
It is not possible to identify all the gasifiers under development or in use throughout the world in this brief discussion. It should be noted that many brands of small air-blown moving-bed gasifiers are commercially available. Most of these are analogous to the Lurgi shown in Table 9-18, except that they operate at atmospheric pres- sure. This decrease in pressure would reduce methane formation and decrease gasifier throughput. Other gasifiers under development uti- liae molten salts, metals, or slags as a medium to improve contact between solid and gaseous reactants. Many of these systems are in too early a stage of development to provide meaningful product-gas and reactant usage information. The use of alkali catalysts to increase the rate of steam-carbon and methane formation is reported as show- ing promise in bench-scale and process-development units (PDUs). The data indicate that lower operating temperatures may be achieved and the use of oxygen eliminated because of the exothermic methane-forming reactions. Further data on catalyst recovery and downstream processing are needed to establish the technical and engineering feasibility of such processes.
Application of Coal Gasification While Table 9-19 mentions some of the products that can be obtained by refining the raw-gas output of the gasifier, application of coal gasification involves consid- erable processing downstream of the gasifier. Figure 9-15 is a com- posite flow plan indicating some of the complexities of such process- ing. The area denoted as “Gasification” includes the supply of coal and gaseous reactants (air or oxygen and steam). The particulate matter, dust, and tars must be removed and the sulfur content low- ered to meet regulations for the combustion of gaseous fuels. At this point, the gasifier output has been converted to a usable fuel: low- Btu fuel gas for air-blown gasifiers and medium-Btu fuel gas for oxy- gen-blown gasihers.
The area denoted as “Product Refinement” includes more com- plete removal of sulfur to avoid deactivation of catalysts; adjustment of gas composition using the water-gas-shift reaction [see Reaction (g-17), Table g-171; and, to produce high-Btu or pipe-line gas (also called SNG), complete conversion to methane [see Reaction (g-18), Table g-171. As can be noted from Table 9-17, the water-gas-shift reaction is slightly exothermic but requires the addition of steam, which results in an energy drain on the overall process. The meth-
anation reaction is highly exothermic, and the heat released is usually utilized to produce steam, which may be used for heating or for pro- viding power.
The centrality of gasification to all coal-conversion processes is illustrated by the end products and their potential uses. The mixture of hydrogen and carbon monoxide produced as synthesis gas may be used to prepare chemicals or converted to liquid hydrocarbons (indi- rect liquefaction). By altering the steam-togas ratio in the shift reac- tor, pure hydrogen may be produced for use in ammonia manufac- ture and petroleum refining. Finally, for direct liquefaction, or hydrogenation of coal, hydrogen must be supplied generally through gasification of coal or unreacted residua of the hydrogenation process.
Gas Purification and Refinement Most of the processing steps shown in Fig. 9-15 upstream and downstream of the actual coal-gas- ification unit are of conventional design. The handling, storage, size reduction, and feeding of coal are discussed in other portions of this section and in other sections of this handbook (see “Solid Fuels: Coal” and “Solid-Fuels Combustion on Stokers and in Suspension” in this section and also Sets. 7 and 8). The removal of particulates and drop lets of oil and tar from raw product gases is also a generally well known processing step. Figure 9-12, depicting a Lurgi gasifier, includes a gas washer of relatively simple but effective design. Addi- tional information on gas scrubbing is available in Sets. 14 and 18, where the engineering of such systems is discussed.
Adjustment of gas composition by the water-gas-shift reaction, using an external catalytic reactor, is shown in Fig. 9-15 and has been previously discussed. The recent development of sulfur-resistant cat- alysts for this reaction allows some choice as to the location of this processing step. Designers of total plant systems have shown a pref- erence for locating the shift reactor immediately after the particu- late-removal units; in a pressurized system, this allows for a high gas exit temperature. This location permits the use of steam in the gasi- fier product gas in the shift reaction and eliminates the need for reheating gases after complete sulfur removal.
An important function of the gas-purification section of a coal-gas- ification plant is the removal of COs and HaS (acid gases). A variety of chemical and physical solvents are offered by various proprietary processes for removing acid gases. Table 9-20 lists one or two typical solvents for each class of absorbents. The alkaline amines and hot
-Garilication_~~ Product Rellnenlenf-
FIG. 9-15 General systems description: surface-coal gasification.
DIRECT COAL UQUEFACTION 9-25
TABLE 9-20 Acid-Gas-Removal Systems for Coal Gas’Scation
sowxx Fleming and Primack (IGT), presented at gist National Meeting, AIChE. Kansas City, MO, April 1976. -
‘Arbitrary number scale, 1 to 10: 1 = poor and 10 = excellent selectivity. futility consumption, 1 to 10: 1 = low and 10 = high utility use. tMEA, methylethanolamine; TEA, triethanolamine.
carbonate solutions react chemically with acidic gases. These solvents require heating to regenerate them and remove the acid gases. As a result, utility consumption is high. Physical solvents can be regener- ated with only minor use of heat energy but operate only at elevated pressure.
An important characteristic is solvent selectivity. For cleansing a gas to be used as a fuel, the only acidic components which must be removed are those containing sulfur. For such systems, a physical solvent such as Selexol (trade name of the Allied Chemical Com- pany) would be ideal. The amine solvents, which were originally developed for use with natural gas, have excellent selectivity vi&- vis hydrocarbons. For facilities which require total removal of sulfur compounds and carbon dioxide for downstream processing over sen- sitive catalysts, more than one removal step may be required to avoid catalyst damage.
Economics of Coal Gasification Many estimates of the costs of coal gasification have been provided in the literature since the early 1970s. Usually, these estimates were outdated by the time they were published. Double-digit inflation increased the costs of almost all capital equipment, labor, and materials. Even though the prices of petroleum and natural gas increased sharply, fuel gases made from coal have not yet become competitive with these naturally occurring products.
Unfortunately, the accuracy of these published estimates is not dependable. A very large portion (as much as 70 percent) of produc- tion cost is related to capital investment for the plant. It is in esti- mating capital investment that most published estimates go astray. These capital costs are obtained by a system of factors. The costs of major capital-equipment items are estimated and these costs multi- plied by various factors to generate costs of installation, piping, instrumentation, electrical needs, etc., associated with these items. These factors have been shown to be not representative of plants han- dling large volumes of gases and solids but to be more typical of liq- uid-processing plants such as oil refineries or chemical plants. As a result, errors of as much as 30 percent have been found when a fac- tored estimate was compared with a line-by-line material-takeoff estimate.
Using 1978 dollars and assuming utility financing in which 75 per- cent of the capital cost is borrowed, it is estimated that synthetic nat- ural gas produced from lignite will cost from $5 to $S.50/10e Btu (1.05 GJ). Such a plant, producing 125 to 250 million scfd (3.5 to 7.0 m3), will require a capital investment of $9KKl to $10,003 per daily 10s Btu of production. This is equivalent to approximately $2.5 bil- lion for a plant producing 250 million scfd of SNG. It should be noted that these costs will vary with inflation and also with the costs of bor- rowed funds. This results in a doubling of the effects of inflation, since interest rates are driven upward by rising costs and decreasing currency values.
In spite of major research and development efforts, it appears doubtful that major reductions in cost can be achieved. Almost 80
percent of the capital cost of coal-gasification plants consists of con- ventional equipment, which will not be altered appreciably by new gasification technology. Improvements will be small in size and slow in being used and will depend on actual commercial implementation of state-of-the-art systems. Only through profit-oriented operation will reliable and practical improvements be real&d.
DIRECT COAL LIQUEFACTION
GENWUL REIFRENCES~ Don&h, Chemistry of Coal Uttlflafton, suppl. vol., ed by Lowry, Wiley, New York, 1963. Gcrin. Chemistry of Coal Uttltmt(on, 2d suppl. vol., ed. by Elliott, Wiley, New York, 1981. Wu and Starch, Hydro- genatkm of Coal and Tar, U.S. Bur. Mines Bull. 6%. 1968
Background The primary objective of any coal-liquefaction pro cess is to increase the hydrogen-carbon ratio and remove sulfur, nitrogen, oxygen, and ash from the coal. Table 9-21 shows the hydro- gen-carbon ratios in proceeding from coal to crude petroleum and gasoline, together with the four techniques for accomplishing these objectives. Direct coal liquefaction refers to any process approach in which coal and hydrogen are reacted at high pressure and temper- ature either with or without hydrogen donor solvent and catalyst. The first three techniques in Table 9-21, direct hydrogenation, sol- vent extraction, and pyrolysis, follow this approach. The fourth, cat- alytic hydrogenation of carbon monoxide, or indirect liquefaction, first converts coal to a synthesis gas, followed by purification and use of a catalyst to form liquid products. An alternative indirect-lique- faction route converts purified synthesis gas to methanol, for fuel use or conversion to gasoline.
The technology of coal liquefaction to synthetic fuels is not new. In 1913 Dr. Friedrich Bergius discovered the technique of adding hydrogen to coal at a pressure of 200 atm (2940 Ibf/ina) and a tem- perature of about 45O’C (842’F). Under these conditions most oxy- gen was hydrogenated to water, some nitrogen to ammonia, and most sulfur to hydrogen sulfide. Hydrogen was also chemically com- bined with the coal to produce a liquid similar to petroleum. Later research at I. G. Farben led to the discovery of catalysts which increased the speed of hydrogen addition to coal. Interest by the US. Bureau of Mines began in 1924 with A. C. Fieldner visiting several
TABLE 9-21 Basic Approaches of Coal Conversion to liquid Hydrocarbons
1. Direct hydrogenation at elevated temperature and pressure, with or without catalysts 2. Solvent extraction (hydrogen donor) 3. Pyrolysis 4. Catalytic hydrogenation of carbon monoxide
Bituminous coal Lignite Crude petroleum Gasoline
HIC 0.8 0.7 1.8 1.9
9.26 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
facilities in Germany, France, and England to become familiar with their coal research. Production of synthetic liquid fuels and chemi- cals from coal in Germany became very noticeable in the mid-1920s. In 1927 the U.S. Bureau of Mines started a laboratory research pro gram on the thermodynamics and kinetics of chemical reactions for the production of alcohols and hydrocarbons from carbon monoxide and hydrogen. By 1939 gasoline was being produced by coal hydro- genation in Germany at 1 million tons/year and in England at 150,000 tons/year.
Research at the Bureau of Mines was also conducted to verify claims of Fischer and Tropsch in 1926 on the discovery of a catalytic technique to produce liquid hydrocarbons similar to petroleum by using water gas at atmospheric pressure and a temperature of 135 to 250% By using a cobalt-copper-manganese catalyst at 275”C, about I.7 gal of oil/1000 fts of gas which contained 34 weight percent of motor fuel could be produced German commercial plants operated at from 1 to 10 atm (14.7 to 1470 Ibf/ins) at catalyst temperatures of 1800 to 21O~C.
In the early 1950s the Bureau of Mines constructed and operated a demonstration plant at Louisiana, Missouri, using the technology of catalytic hydrogenation of coal and carbon monoxide to produce liquid fuels. Research in the chemistry of coal liquefaction since then has produced several modifications of the four types of liquefaction processes. These include catalytic hydrogenation in fixed and ebul- lated beds, zinc halide hydrocracking, reaction of carbon monoxide- rich synthesis gas and steam with coal, and a combination of solvent extraction and catalytic hydrogenation in two-stage liquefaction.
Currently, the most advanced direct coal liquefaction processes are solvent-refined coal (SRC), Exxon donor solvent (EDS), and H- Coal. These are compared in a generalized flow diagram, Fig. 9-16, and discussed in greater detail later.
Direct-Liquefaction Kinetics All direct-liquefaction processes may be considered to consist of three basic steps: (I) coal slurrying in a vehicle solvent, (2) coal dissolution under high pressure and tem- perature, and (3) transfer of hydrogen to the dissolved-coal products.
In the temperature range of 350 to 450% (662 to 842OF) the coal is dissolved in about 1 min. Solvents are assumed to promote thermal cracking of coal into smaller, more readily dissolved fragments. These may be stabilized through reactions with each other or with hydrogen supplied either by a donor solvent or in a gas phase.
Data on Illinois, River King (hvCb), and Kentucky No. 9 (hvBb) coals were used by Wen and Hahn to obtain a rate equation for coal dissolution under hydrogen pressure. These data included a temper- ature range of 375 to 500°C and pressures up to 136 atm (O-2090 psig). An empirical rate expression was proposed as
._._._.-.a+._._ I Lt. Ends H,S. NH,, H,D, CH.
Bate of dissolution = rate constant X fraction of undissolved solid organics X coal-solvent ratio
rA = kc, exp -E/RT exp (0.006684 Pns)(C,J(l - r)(C/S)
where T,, = c, =
ko= PHp =
X= c/s =
rate of dissolution, g/(h.cms) reactor volume weight fraction of organics in unreacted coal rate constant, g/(h.cm3) reactor volume I.. drogen partial pressure, psia conversion, solid organics/solid organics in original coal 1 t . . . coal-solvent weight rat10
By assuming an Arrhenius temperature dependency, calculated and experimentally reported conversions agreed well for the following values:
(9-21)
Constant Illinois. River Kim? (h&b) Kentuckv No. 9 (hvBb)
212.5 g/(h’cm3) 11 kcal/(a~mol~
15.3 g/(h.cm’) 4.5 kcnl/(g~mo~)
The small values of activation energy suggest that the dissolution rate is controlled by counterdiffusion of organic components from the coal surface and dissolved hydrogen from the solvent-hydrogen mixture. Also, the rate of dissolution appears to be exponentially dependent on hydrogen partial pressure.
A free-radical mechanism was also proposed for coal dissolution in hydrogen donor solvents. Initial dissolution was considered a thermal process, with a net rate dependent upon the type of solvent and its effectiveness in stabilizing free radicals. The greater a solvent hydro- gen donor capability, the more effective it is in terminating radicals. An overall rate-limiting step in the process appears to be rehydro genation of the donor solvent.
A mixture of Kentucky No. 9/14 (hvBb) coal and creosote oil was used in the study at a 3: 1 solvent-to-coal ratio. Hydrogen solubility was experimentally measured over 100 to 4oO°C and 500 to 3000 psia, simulating the high temperature and hydrogen partial pressure of coal-liquefaction reactors. The first-order-reaction model obtained from hydrogen-absorption data expressed total hydrogen consump- tion as
An Arrhenius plot of hydrogen-transfer rates gave an activation energy of 21 kcal/mol and a frequency factor of 1.06 X ld min-‘. From these values it appears that mass-transfer effects are small and that the hydrogen consumption rate was kinetically controlled.
Solvents and heat facilitate thermal degradation of coal to form relatively low-molecular-weight free radicals. These may be stabi- lised by hydrogen transfer from a hydroaromatic solvent. The func- tions of dissolved gaseous hydrogen and catalyst are to rehydrogenate the solvent. Catalysts are considered to be primarily responsible for nitrogen and sulfur removal and the formation of light liquid products.
A first-order hydrogen absorption in creosote oil was proposed with creosote oil being considered a good representative for steady- state, coal-derived solvent. The progress of coal conversion was mea- sured on the basis of a fraction of organic products soluble in benzene or pyridine. At conversion above 90 percent these results will be very similar.
The rate of consumption of gas-phase hydrogen in the liquefaction reactor was expressed as
- rH1 = ; % = k&P, - PHy) (9-23)
where rHp = rate of consumption, (g.mol)/(cmr~ h) S = surface area for absorption, cm*
NH2 = mole of hydrogen, g. mol ks = z$de mass-transfer coefficient, (g.mol)/(cmr’h.
Pm = hydrogen partial pressure, atm P Hp( = hydrogen partial pressure at gas-liquid interface, atm
Integrating this over the reactor length,
-ln O’HPO/YH~,) = k&PTVdFC (9-24)
where kp = ;;emr)all gas-absorption coefficient, (g.mol)/(h.cms.
RI = liquid holdup PT = total pressure, atm VR = reactor volume, cm3 Fc = total gas flow rate, (g.mol)/h
The liquid holdup Rr may be estimated by use of the Lockhart-Mar- tinelli correlation for large-diameter reactors or the Nicklin correla- tion for smaller diameters, less than 7 cm.
Temperature, reactor hydrodynamics, and catalyst affect the over- all gas-absorption coefficient (kp). Values of (k@) are presented in Fig. 9-17 and show that increasing temperature and turbulence increase kp for both catalyzed and noncatalyzed systems. As shown in Fig. 9-18, increasing turbulence, which reduces diffusion barriers, has more effect on catalyzed systems when reaction rates are higher. The pressure effects on the coal-dissolution coefficient were observed to be P”uz for PH2 > 50 atm.
Bituminous coals begin to soften in the 325-350°C temperature range. Rapid mixing will increase both heat and mass transfer in this regime by reducing diffusion resistance to hydrogen at the solid-liq- uid boundary. The effect of the slurry Reynolds number on the coal- dissolution rate is shown for three coals in Fig. 9-19. Increased hydro- gen absorption for catalytic as compared with noncatalytic systems is due to the further hydrogenation of coal liquids to lighter products and to sulfur and nitrogen removal.
The conversion reaction from coal to oil has been modeled as a series of steps:
Coal + solvent - preasphaltene - asphaltene - oil
with some gas formation accompanying each step. In a study using Illinois No. 6 coal, Burning Star Mine (hvCb), and process-derived heavy distillate (232 to 454%) data were obtained at 13.8 MPa (2060 Ibf/in”) and 400 to 475°C. Activation energies for the steps of the reaction series were determined to be
which appears consistent with published molecular-weight values of solvent (250), preasphaltene (1000) and coal (2250).
A more complex reaction model was proposed from the results of a kinetic study of thermal liquefaction of Belle Ayr subbituminous coal. Data were obtained over a temperature range of 400 to 470% (752 to 878OF) at 13.8 MPa (Zoo0 psig) by using two solvents, hydro- genated anthracene oil (HAO) and hydrogenated phenanthrene oil (HPO), at a coal-solvent ratio of 1: 15. Results were correlated with the following model;
cl;, _+w
Asphaltem
Activation energies and frequency factors for the various steps of this model were determined as follows:
Reactor Rate
constant
Activation e;o;y kcal/(g’
Coal-HA0 Coal-HP0
Frequency factor, min-’
Coal-HA0 Coal-HP0
Coal - oil K. 14.1 26.9 2.1 x 10s ConI- preasphaltene Coal - asphaltene
b 13.8 4.3 4.94 K. 15.6 6.6 1.12 x 10’ 9.63 X 10’
coal-gas K, 21.5 10.5 6.72 X ld Preasphaltene - asphaltene K, 12.6 33.9 9.66 x lop E :: :z Asphaltene - oil L 16.0 25.6 1.42 X ld 1.53 x 10’
9-28 ENERGY UTIUZAlION, CONVERSION, AND RESOURCE CONSERVATION
1.3 1.4 1.5
‘03/T(K-‘1
(0)
s ‘84 . 7 s 10-S
0 1.34 1.36 1.38 1.40 1.42
2 103/T(K-‘)
(b)
FIG. 9-17 Effect of temperature on the coal-dissolution-rate coefficient including hydrodynamic influence (n) Noncatalytic systems. (b) Catalytic systems.
Magnitudes of K , K,, K., and K, indicate the importance of direct reactions wit t coal, where K, and K, are hydrocracking reactions in the conversion process. Data for K, and K, from the experiments with HP0 show the effect of an effective hydrogen donor solvent on product yield and indicate that oil production from coal will be increased by the use of a good hydrogen donor solvent.
The ability of coal minerals to catalyze the hydrogenation creosote oil and Kentucky coal has been investigated. Catalytic materials investigated are listed in Table 9-22. Hydrogen partial pressure was used as a measurement of hydrogenation activity for these materials as shown in Fig. 9-20. Desulfurization results are contained in Fig. 9-21. Data for both tests of catalytic activity are in general agree- ment for all except two materials. First, pyrite was determined to be ‘an effective hydrogenation catalyst but poor for desulfurization. Set-
Ill1 I Temp 445°C
‘o-5- 2 5 ‘0 2 5 ‘02 2 3 103 2
Slurry Reynolds number AeL
FIG. 9-19 Effect of slurry Reynolds number on the hydrogen-absorption-rate coefficient {or catalytic and noncatalytic coal-liquefaction systems.
2 10 10 10
Slurry Reynolds number Re,
FIG. 9-19 Effect of the slurry Reynolds number on the rate of coal dissolution for Kentucky, Illinois, and West Virginia coals.
ond, contrasting results were obtained in the catalytic-activity exper- imental results for iron. Thus, differences in the composition of coal- ash minerals will determine their effectiveness for hydrogenation or hydrodesulfurization activity in coal liquefaction.
Direct-Liquefaction Processes
Solvent-Refined Coal (SRC) This process was initiated by the Pittsburgh & Midway Coal Mining Co. in the early 1960s.
SRC-Z process. In the SRC-1 (solid-fuel) operating mode, shown in the flow diagram of Fig. 9-22, pulverized coal is mixed with pro- cess-derived solvent. After adding hydrogen, the slurry is pumped through a preheater and into a dissolver which operates at 425 to 470°C (800 to 878OF) and a pressure of 10 to 14 MPa (1450 to 2030 lb/in’). Coal conversions of 92 to 95 percent are achieved during the residence time of 20 to 60 min. The dissolver effluent is separated into gases and slurry in a separator. The raw gas is scrubbed with a dilute caustic solution to remove hydrogen sulfide and carbon diox- ide. A portion of the scrubbed gas is purged to prevent accumulation of noncondensables (C,-Cd hydrocarbon gases and CO), but most of the gas is recycled back into the process. The slurry product, after being cooled to 315OC (6OOOF) and depressurized to 0.8 MPa (116 lbf/in”), is passed through a precoated rotary drum or leaf filter to separate undissolved coal and mineral matter from the SRC solution. In a commercial plant, these residues would be sent to a gasifier to produce process hydrogen. The filtrate is vacuum-distilled to sepa- rate the solvent from the nondistillable product (SRC), which is then solidified by cooling. The SRC product is almost ash-free (<O. 16 per- cent) and has a sulfur content of 0.6 to 0.9 percent and a heating value of approximately 37.2 MJ/kg (16,009 Btu/lb). Typical oper- ating conditions and product yields for SRC-I are shown in Table 9- 23.
Studies have indicated that bituminous coals of Kentucky No 9 and No. 14, Illinois No. 6, and Indiana V are attractive for use in the SRC process but that Wyodak subbituminous coal and Utah bitu- minous coal are not. It appears that certain components of mineral matter in coal, iron compounds in particular, may have a catalytic effect on hydrogen transfer, resulting in an increase in coal conver- sion. High-vitrinite and low-oxygen contents of the coal are also desirable to achieve high SRC yield at low hydrogen consumption.
SRC-ZZ process. The SRC-11 process is an improved version of the SRC process, recycling a portion of the reactor effluent slurry in place of the distillate solvent of the original SRC-I process. Because of increased severity of operating conditions in the SRC-11 process, the primary product is a liquid distillate fuel with a 217 to 455% (42.3 to 851°F) boiling range. The fIow diagram of the SRC-II oper- ating mode is shown in Fig. 9-23. The general process is the same for both modes from the slurry-mix tank through the dissolver. In the SRC-II mode, however, the dissolver slurry is split into two streams; one is recycled to the slurry mix tank, while the other is passed into a vacuum-flash unit. The vacuum-flash condensate is fractionated to
TAME 9-22 Derriotion of Ceal Minerals or Catalvtic Aaents Studied
SDeties Classification Descrivtio”
Ankerite (ferriferrous dolomite)’ Calcite’
Carbonate Carbonate
An isomorphorus mixture of CaMg(CO& and CaFe(CO& A crystalline form (hexagonal scalenohedral class of the hexagonal system) of CaCOa. Often, to
a small extent the Ca is replaced by iron, magnesium, and manganese Clay, sand, bitumen, and other mechanical impurities may be present.
A double salt with equal molecular quantities of CaC03 and MgC03 and not a” isomorphous mixture of these two compounds; usually found in a curved rhombohedral form.
A common type of clay; often found in minute pseudohexagonal (monoclinic) crystals; chemically, a” acid aluminum silicate, H,Al,Si& or 2HeO-A&03-2SiOo (He0 = 14%) Iron is often present is small amounts.
Dolomite’
Kaolinite’
Carbonate
Kaolin
A lamina-type silica substance. having a monoclinic crystal structure, and chemically classified as a” acid Dotassium aluminum orthosilicate. H~KAI&iO.h or ~H&KvO-~AIQOV 6SiOz(Hzd = 4.5%). Often, the potassium ii pa&$ rep&xl by;odi&, and s&e varieties contain a” excess of silicon over that indicated
A cubic structure of Fe&. having in its crystalline structure a rock-salt type of arm” ement of Fe*+ and S% ions, with iron being octahedrally surrounded by S and each S atom $ avlng one S and three Fe atoms as neighbors. Uncommonly, Ni, Co, or sometimes both are found substituted for Fe. Obtained from M&hewn, Coleman, and Bell (90-955 pure).
A crystalline form of SiOl, a member of the triagonal trapezohedral class of the hexagonal system.
Muscovite’ Shale
A crystalline form of FeCOs, with the brown to gray crystals usually being rhombohedral. Calcium, magnesium, and manganese are usually present in small amounts as replacing elements.
Pyrite Sulfide
Quartz’
Siderite’
Accessory
Carbonate
Commercial catalyst from Laporte Industries, Inc. (Comox 451, 1.5.mm extrudute); surface area = 300 m’/e. “ore volume = 0.66 mL/e. Chemical analvsis: 3.7. 12.8. 0.06. 1.4. and 0.03% Coo. M&,~Na~O. NazO + Kz, SiOp,-and SOa respectively.
Reagent-grade hydrogen-reduced iron from Mallinckrodt, Inc. Solid residue from hydrogenation-of-creosote oil in presence of 15% by weight of Fe& at
425T, stirrer setting of 2OtM r/min, and 3OOO psig of initial hydrogen pressure Obtained from filter cake from Wilsonville SRC pilot plant. Analysis: 55.2% ash content and
13.6% S for -325mesh material; and, prior to screening. 30% filter aid, 53.6% ash, and 2.9% s.
CUM-AI
Iron Reduced pyrite
SRC residue
Cd ash Obtained by burning Kentucky No 9/14 mixture (7 2% ash) in a muffle furnace at 1CCVC; analysis: 13.7% iron.
Kaolin Obtained from W. H. Curtis and Co.
‘Minerals obtained from David New, Minerals and Books, Providence, Utah. NOTE: Al1 agents were ground to -325 mesh prior to use, except muscovite. which was ground onlv to -80 mesh because of its laminar silica structure. and
FIG. 9-20 Comparison of hydrogenation activity of catalyst
9-29
9-30 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Original % sulfur in creosote oil
FIG. 9-21 Comptin of desulfurization activity of catalyst.
yield naphtha and middle and heavy distillates. The vacuum residue is heavy oil, unreacted coal, and mineral matter.
The increased conversion to light products in the SIG11 process results in a higher hydrogen consumption of about 4 to 5 percent, as compared with 2 to 2.5 percent for the SIX-1 process. This is caused by the longer residence time, higher operating pressure, and recycle of coal solution with mineral matter, allowing more hydrocracking in the dissolver.
MMEUP
HYDROGEN
COAL
Ir
Because the mineral residue is separated as vacuum-flash bottoms along with the undissolved coal, the solid-liquid separation step of the SRC-I mode can be eliminated in the SRC-II mode. The degree of dissolution of coal and the distribution of products depend greatly on the reactivity of the coal feed. Three high-volatile bituminous coals have been tested to determine the effects of dissolver temper- ature, coal-slurry feed rate, and coal concentration on product yields.
The material balance runs with western Kentucky coal, Illinois No.
I .HC GAS
4 RECYCLE HYDROGEN
A )PURGE GAS
r I
I
I GAS I--+ TO SULFUR RECOVERY UNIT PURIFICATION
RECYCLE SOLVENT b PROCESS
SOLVENT
1 T ’
+ PREHEATEA + DISSOLVER ---) OIL
SEPARATOR __) PRODUCT
FRACTIONATDN b NAPHTHA
+ RESIDUE SRC
FIG. 9-22 SK-1 process scheme.
DIRKT COAL LIQUEFACTION 9-31
TARlR 9-23 SRGI Product Yiilds from Pilot Plant
Operating conditions
Coal
Coal (maf) feed rate Western Kentucky 9 and 14
solvent feed rate 1837 kg/h (4050 lb/h)
Hydrogen purity in feed gas 2860 kg/h (6305 lb/h) 94 mole 5%
6 coal, and Blacksville No. 2 Pittsburgh Seam coal indicated that a higher distillate yield was obtained at decreased coal concentration and increased dissolver residence time. This is shown in Fig. 9-24 for western Kentucky coal. The test results with the three coals are sum- marized in Table 9-24. The western Kentucky and Illinois No. 6 coals are more reactive than the Blacksville No. 2 Pittsburgh Seam coal.
Exxon Donor Soloent (EDS) Process The Exxon Research & Engineering Co. has developed the EDS process, which also liquefies coal with a hydrogen donor solvent under hydrogen pressure. The solvent, however, is a catalytically hydrogenated recycle stream frac- tionated from the middle boiling range, 201 to 455OC (395 to 85O“F), of the liquid product. The liquefaction system is an upflow, tubular plug-flow reactor which is divided into four sections illus- trated in Fig. 9-25. The hydrogenated recycle solvent is mixed with fresh coal feed and pumped through a tubular preheat furnace into the liquefaction reactor. The reactor operates at 427 to 471“C (309 to fBO’F) and 10.3 to 13.8 MPa (1490 to 2000 lbf/inr), similar to the conditions of SRC-II.
The reactor effluent is separated by distillation into light hydro- carbon gases, naphtha, distillates, and vacuum bottoms. The vacuum bottom, 63WC+ (1180’F+), may be treated with air and steam in Exxon’s proprietary Flexicoking process to produce some heavy oil,
MAKEUP
HYDROGEN
36
::I 20 22 24 26 28 x) 32 34 36 38
Feed slurry cmcenfrotm. wght percenl
FIG. 9-24 Effect of coal concentration and nominal dissolver residence time
on total distillate yield in the SRC-II operating mode (western Kentucky coal, 46OT. 13.1 MPa).
a low-heating-value flue gas, and a mineral-ash residue. The process hydrogen is produced by the steam reforming of Ci-Cd hydrocar- bon gases produced in the hydrogenation reactors.
The hydrogenation of the recycle solvent is conducted in a con- ventional fixed-bed catalytic reactor by using hydrotreating catalysts such as cobalt molybdate or nickel molybdate. Coal conversion and liquid yield strongly depend on the molecular composition, boiling- point range, and other properties of the solvent. Exxon uses its pro prietary Solvent Quality Index (SQI) as the main criterion of solvent quality and correlates product yields with SQI. The SQI can be con- trolled by adjusting the hydrotreater temperature, and coal conver- sion, product yields, and hydrogen consumption decrease signifi- cantly when the SQI is less than a certain value. This critical SQI appears to depend on the coal type and liquefaction conditions, and solvent quality requirements are significantly reduced when molec- ular hydrogen is present in the reactor.
The solvent has two major roles in the liquefaction process: (1) to stabilize the liquid products by donating hydrogen to the coal and (2) to disperse and transport the coal particles through the liquefac-
4 RECYCLE HYDROGEN
t
b PURGE GAS
COAL RECYCLE SLURRY v
FIG. 9-23 SRC-II process scheme.
9-32 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TABLE 9-24 SRC-II Product Yields from Pilot Plant
Coal Western Kentucky Illinois No. 6 Blacksville No. 2
tion system. The specific feature of the EDS process is that the cat- alyst used in the process is not in contact with the high-molecular- weight asphaltenes, preasphaltenes, or mineral matter, thereby preventing fast deactivation of the catalyst. The use of vacuum dis- tillation provides a residue,_which in addition to Flexicoking, may be used as a fuel or feed to gasification for hydrogen generation.
Several coals including bituminous, subbituminous, and lignite coals have been tested Different coals gave different liquid-yield response with a change in operating conditions. For Illinois No. 6 bituminous, Wyoming subbituminous, and Texas lignite, the conver- sion increased only slightly after 40 min. The low-rank coals gave slightly higher conversion, owing to higher yield of water and carbon oxides. The C, 638% (811 K) liquid yields, on the other hand, is adversely affected at long residence times owing to the cracking of liquids to gases. The optimum residence time is about 40 min for Illinois No. 6, 60 min for Wyoming, and 25 to 40 min for Texas lig- nite. Table 9-25 shows the liquefaction product yields at these pre- ferred operating conditions. These results have been confirmed in a 2.%ton/day pilot plant.
H-Coal Process This process has been under development by Hydrocarbon Research, Inc., since 1964. Operation at laboratory and process-development-unit (PDU) scales of up to 3 tons/day has been
CATALYTIC
confirmed by a 600_ton/day pilot plant using various coals and dem- onstrating satisfactory control of catalyst bed expansion.
This process can be operated in either a fuel-oil mode or a syn- crude mode, depending on the type of fuel desired. The flow scheme of the H-Coal process is shown in Fig. 9-26. Coal, which has been ground to -60 mesh and dried, is mixed with recycle oil, pumped to 20 MPa (2900 Ibf/in”), and mixed with compressed hydrogen. The mixture is preheated to 371°C (7OO’F) and fed to the bottom of the ebullated-bed catalytic reactor. The catalyst is kept in a fluidized state by the upward flow of the slurry and gas through the reactor. Catalyst activity is maintained by the addition and withdrawal of small quantities of catalyst to and from the reactor. The reactor also contains an internal tube for recirculating the reaction mixture through the catalyst bed. The reactor temperature is kept at 454% (849OF). Vapor products leaving the top of the reactor are cooled to separate a liquid condensate. The gas stream is sent to a scrubber to absorb light hydrocarbons, ammonia, and hydrogen sulfide. The remaining hydrogen-rich gas is recycled. The condensate from the reactor vapors is released to atmospheric pressure and fed to an atmospheric still. The liquid-solid product from the reactor is let down to the atmosuheric-oressure flash separator. The lighter hydrrr carbon liquids that are tlashed off are sent to the atmospheric still.
H, LIQUEFACTION DISTILLATION
HYDROGEN
FLEXICOKING 1’ , FUELGAS
FtG. 9-25 Flow scheme of the Exxon donor solvent process
The bottoms product from the flash separator is further separated with a hydroclone, with a liquid-solid separator, and by vacuum dis- tillation. The atmospheric still yields light and heavy distillates, and the vacuum still yields heavy distillates and residual fuel. A portion of the heavy distillate and hydroclone overflow is recycled as the
slurry vehicle. The severity of operating conditions of the H-Coal process affects
the type of fuel produced. In the fuel-oil mode, a relatively hiah slurr;space velocity of 1.25 Mg/(h.ms) of reactor is used. The re&- tor space velocity can he related to the residence time of the slurry phase in the H-Coal reactor. The hydrogen partial pressure is low- ered to about 12 MPa (1740 Ibf/ins); hydrogen consumption is usu- ally less than 4 weight percent based on dry coal. In general, at lower hydrogen partial pressures there is less Hz pickup by the oils, result- ing in higher residuum and lower distillate yields. Table 9-26 shows the product yields obtained at PDU by using an Illinois No. 6 bitu- minous coal. The catalyst was cobalt molybdate on an alumina sup- port. A 0.49 percent sulfur fuel oil [205”C (399”F+)] was produced at 3.3 weight percent hydrogen consumption.
Table 9-26 also shows the results obtained in the syncrude mode
Hydrogen -
Coal preparallon
Coal feed rate, Mg/(h.ms) Recycle oil-coal ratio
Reactor temperature, T (OF) Hydrogen partial pressure, MPa (Ibf/ins) Yields, weight 96 of dry coal
Hs consumption, weight pb of dry coal 3.80 5.25 Sulfur in 205OC+ (399”F+) oil, weight X 0.49 0.26
operating at a space velocity of 0.53 Mg/(h.ms). In general, with all other variables held constant, the decrease of the space velocity decreases the residuum yield but increases the naphtha yield. The hydrogen consumption is higher in the syncrude mode, at 5.25 weight percent based on dry coal. The total liquid yield was 73 weight percent and 76 weight percent on an maf coal basis for the syncrude and fuel-oil modes respectively.
As with the SRC processes, one of the major problems has been solids separation. The H-Coal process uses hydroclones to remove about two-thirds of the solids from recycled liquid employed as the vehicle. In the syncrude mode, the separation of unreacted coal and ash from the liquid can be accomplished by vacuum distillation. In
H y drog”yt i-$r”carbqn gas
Regenerated catalyst
Condenser 20 MPa
j llquld
1 I
I\X.. I I SOild I I 111 I
Recycle - tube
i
Fired preheater 371 ‘C
L Impeller shaft
Yl=
Vacuum still
I
Residual + fuel
Recycle heavy distillate
RG. 9-26 H-Coal process scheme.
9.34 ENERGY UTIUZATK)N, CONVERSION, AND RESOURCE CONSERVATION
FIG. 9-27 COED coal pyrolysis
the fuel-oil mode, however, an efficient solid-liquid separation method is needed. An antisolvent-precipitation method has been selected.
Coal-Pyrolysis Processes Another approach to coal liquefaction is pyrolysis, which produces synthetic crude oil, gas, and char as demonstrated in the COED process shown schematically in Fig. 9- 27. Crushed coal is dried and heated to successively higher temper- atures in a series of Euidized-bed reactors. In each stage, a portion of the coal’s volatile matter is released, with each stage maintained slightly below the temperature at which it would agglomerate and detluidize. Typically, four stages of 316, 454, 538, and 816OC (600, 850, 1000, and 15OO’F) were used, but operations varied owing to the different coal-agglomerating properties. Process heat was gener- ated by burning char in the last stage and circulating hot char and gases to the other stages. Volatile products were condensed in a recovery system and pyrolysis oil filtered to remove fines. The fil- tered-oil product was hydrotreated in a fixed-bed reactor with hydrogen at 371 to 427OC (700 to 8OO“F) to remove sulfur, nitrogen, and oxygen, thus producing a 25 to 30° API synthetic crude.
Typical operating conditions and pyrolysis yields for two bitumi- nous coals, Utah A and Illinois No. 6, are presented in Tables 9-27 and 9-28. These results were obtained from a 36-ton/day coal pilot plant at Princeton, New Jersey. Higher net oil product yield, 1.23 versus 1.10 bbl/ton, was obtained from the Utah coal than from the Illinois coal. The major problem with any pyrolysis process is the high yield of char.
Flash Pyrolysis and Hydropyrolysis Pyrolysis of coal at ele- vated temperatures for a s&t r&idence time, c&d flash pyrolysis, produces gases, liquids, and char. The increase in hydrogen content in the gases and liquids is the result of removing carbon from the process as a char containing a significantly reduced amount of hydro- gen. Several processes have been tested on a relatively small scale.
TABLE 9-27 Pwdnir Yield Data
Illinois No. 6 wzam Utah A seam
Net yields, weight 9b dry coal
Char Oil
Gas Liquor
59.5 54 5 19 3 21.5
15.1 18.3 6.1 5.7
Net lkes~ yields
Char, lb/ton
Oil, bbl/ton Gas, rf/ton
1190 1090 1.10 1.23
6610 8545 Liquor, gal/ton 14.6 13.7
None have demonstrated economic potential, although the technical concepts may be valid.
Flash hydropyrolysis, which is the rapid pyrolysis of coal in the presence of pressurized hydrogen, could improve the oil product quality and liquid yields. It requires large usage of hydrogen.
The Occidental Research Corporation (OK) flash pyrolysis pro- cess consists of rapidly pyrolyzing coal particles at a temperature of 621 to 679% (1149 to 1254OF) in an entrained stream of hot coal char and gas. The process takes advantage of the high heating rates that are made possible by recycling the hot char, and it gives the highest liquid yield of the pyrolysis processes. The process has been tested in a S-ton/day PDU.
Flash hydropyrolysis, the noncatalytic short-residence-time hydropyrolysis of coal, is a process for producing light aromatic liq- uids and gaseous hydrocarbons. Product distribution and yields are greatly influenced by temperature and time because of competitive reactions between fragmentation of repolymerization. Several research organisations are undertaking developmental programs by using bench-scale units to determine operating conditions for maxi- mizing the production of high-quality distillate liquids by rapid- heat-up noncatalytic hydropyrolysis.
In the Brookhaven National Laboratory unit pulverized coal is mixed with hydrogen preheated to 775’C (1427OF), and the mixture is fed into the top of a downflow tubular reactor. With North Dakota lignite at temperatures in the range of 78 to 750°C (1337 to 1382OF) and 13.8 MPa, the maximum yield of the heavier liquid hydrocarbons (> C,) is approximately equal to that of the BTX yield.
The Institute of Gas Technology used a coil reactor in its bench-
TABLE 9-28 Typical Propertier of p/ro@s Oils
Properties of derived coal:
elements analysis Utah A seam
Weight X, dry C&O” 83.8
Hydrogen 9.5
Nitrogen 09 Sulfur 0.4
Oxygen 5.0
Ash 0.3 API gravity, 60°F -3.5
Moisture, weight % 0.5 Pour point, OF 100
Viscosity, SUS 2lOOF 390 Solids, weight %, dry basis 3.8
Gross heating value, Btu/lb 16,lCQ
Illinois
No. 6 seam
79.6
7.1
1.1 2.8
8.5
0.9 -4
0.8 100
1333 4.0
15050
INDIRECT COAL LIQUEFACTION 9-35
Coal + Gaslflcatlon Purlflcotlon of Liquefaction oxygen + tocorbon monoxide + synthesis + via catolytlc . + Product
Steam + and hydrogen ws synthesis
Ho. 9-20 Generalized Bow diagram for indirect liquifaction.
scale unit to investigate hydrocarbon yields from North Dakota lig- nite at operating pressures of 3.5 to 13.8 MPa. At 13.8 MPa, carbon conversions and yields of hydrocarbon liquids were higher. During normal operations, pulverized coal is gravity-fed to the reactor from a feed hopper, and carrier gas is supplied on a once-through basis. The residence time of the reactants is varied by altering the coal and the carrier-gas Bow rates. On the basis of the results of bench-scale studies, a 23- to 45-kg/h riser reactor PDU has been designed. Recent bench-scale studies with Illinois No. 6 bituminous coal showed that yields of hydrocarbon liquids were greater than those obtained from North Dakota lignite under similar processing conditions. To explore methods for handling caking coals, silica sand has been mixed with coal as a dry diluent.
Cities Service Co. tested several bituminous coals and lignites in a bench-scale unit to determine operability in a small-diameter, entrained-tlow hydropyrolysis reactor and relative reactivity toward carbon conversion. The tests were made at an average temperature of 704OC (1299”F), hydrogen partial pressure of 15.2 MPa, and a residence time of about 3 s. Carbon conversion ranging from 35 to 75 weight percent was obtained with carbon selectivities of about 30 to 35 percent to liquids.
Rocketdyne has been testing its flash-hydropyrolysis process in a l-ton/h PDU to study residence time and reactor hydrogen require- ments. Pulverized coal is fed from a high-pressure feeder into the entrained-flow reactor, where it is mixed rapidly with high-temper- ature hydrogen by using a rocket-engine injector element. The reac- tor is generally operated at temperatures in the range of 760 to 1037°C (1400 to 1898°F). The residence time is 20 to 200 rns, and the operating pressure is in the range of 3.4 to 10.3 MPa (493 to 1493 Ibfjir?). A hydrogen-to-coal-feed ratio as low as 0.16 by weight was
Coal a- Prep. High Trmprrature and
Moderato Presruro
achieved. Overall conversions of about 60 percent can be obtained, yielding a plant thermal efficiency of about 75 percent if the char is gasified to supply the process hydrogen.
INDIRECT COAL LIQUEFACTION
GENERAL REPERENCES: Lowry (ed.), Chemistry Of Coal LJtiliZ(ltiGn, vols I and II, Wiley. New York, 1945. Lowry (4.). Chemf.stry of Coal UrUitatfon, suppl. vol., Wiley. New York, 1963. Starch, Golumbic, and Anderson, The Fischer-Tropsch and Related Syntheses, Wiley, New York. 1951.
Fischer-Tropsch Synthesis A general schematic approach for all indirect-liquefaction processes is shown in Fig. 9-28. All use the basic Fischer-Tropsch (F-T) reactions to produce liquids from hydrogen and carbon monoxide.
The F-T synthesis differs from the direct-liquefaction processes described earlier in that it involves catalytic reactions between mix- tures of hydrogen and carbon monoxide, so-called synthesis gas (syn- gas), which can be made by steam-oxygen gasification of coal or other hydrocarbons. The F-T synthesis produces largely paraffinic and olefinic hydrocarbons instead of the predominantly aromatic hydrocarbons from direct coal liquefaction.
The basic reactions in the F-T synthesis follow:
(en + l)HZ + nC0 = C,H,.+, + nH,O (9-E)
2nHz + nC0 = C.H1. + nH~0 (9-26)
(n + l)He + 2nC0 = C.Hs.+z + nCOz (9-27)
nH, + 2nCO = C.H,,+ nCOp (9-28)
2nH2 + nC0 = C.&+,OH + (n - 1)H20 (9-29)
FIG. 9-29 Simplified process diagram for the SASOL-I Fischer-Tropsch process
9-36 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Reactions (9-25) and (9-27) yield paraffins, (9-26) and (g-28) olefins, and (9-29) alcohols.
SASOL (an acronym in Afrikaans for South African Coal, Oil, and Gas Corporation) is the only commercial F-T plant in operation. The first plant, SASOL-I, was completed in Sasolburg in 1955; it is shown schematically in Fig. 9-29. Two additional plants, SASOL II and III, are now in operation.
SASOL-I includes both fixed- and fluid&d-bed Synthol reactors. SASOL-II uses only fluidized-bed reactors since they produce a higher percentage of transportation fuels.
A typical Synthol product slate follows:
Product
Methane Ethane and ethylene Propane and propylene Butanes and butylenes Cs to 375°F fraction 375 to 75O’F fraction’ 750 to 970°F fraction Heavier than 970°F fraction Chemicals
Total
‘Gasoline.
Yield, percent/weight
11.0 7.5
13.0 11.0 37.0 11.0 3.0 0.5 6.0
loo.0
It has been estimated that the installed cost of a SASOL-II type of plant in the United States would range from $2.5 to $36 billion (based on 1979 dollars), depending on where it was constructed. This corresponds approximately to $60,000 per daily barrel.
Other approaches have been investigated for selectively making specific materials from syngas. Some have culminated in well- known, widely used processes such as those for making methanol and acetic acid. More particularly, the approaches being pursued by the Mobil Research and Development Corporation are especially attrac- tive because they show great promise of being the basis for making high-octane gasoline on a large scale from coal via syngas and meth- anol or directly from syngas without simultaneously making by- products for which it may be difficult to find markets. Thus Mobil’s approaches appear to avoid one of the major stumbling blocks to the use of Fischer-Tropsch chemistry for making gasoline from coal, namely, the many higher-molecular-weight hydrocarbons and oxy- genated organics produced by that chemistry along with the gasoline.
Methanol-tc-Gasoline Process Mobil has developed a family of proprietary catalysts which make a mixture of hydrocarbons in the gasoline range with high selectivity from methanol. The mixture has a research octane number in the 93 to 94 range; the only by-products are water, a relatively small quantity of LPG materials, and even smaller quantities of methane and Cn hydrocarbons. Practically no materials having molecular weights above the gasoline range are pro duced. Because of the selectivity of the Mobil catalysts and because methanol can be made with great selectivity from syngas, which could tX made from coal, the Mobil catalysts provide a potentially promising route for making gasoline on a large scale indirectly from coal without simultaneously making any by-products which might be difficult to market.
Syngas-to-Gasoline Process Mobil has also developed another group of proprietary catalysts which convert syngas with notable selectivity directly into a mixture of hydrocarbons in the gasoline range. Unlike the Fischer-Tropsch catalysts, the Mobil catalysts pro-
duce high yields of high-octane gasoline and only trace amounts of oxygenated organics or hydrocarbons having molecular weights higher than those in gasoline. Some of the Mobil catalysts produce olefinic gasolines, and others produce aromatic gasolines. Some reject oxygen in the form of water, and others do so in the form of carbon dioxide. The other by-products of the Mobil catalysts are LPG mate- rials, CI hydrocarbons, and methane.
Preliminary aging tests suggest that some of the catalysts can be regenerated, and some also exhibit relatively long service lives. This preliminary work had been done in microscale units having the capacity for about 10 cm3 of catalyst in a fixed bed. Larger units (100 cm3 of catalyst) for both fixed- and Ruid-bed operation have now been built and are in shakedown testing.
ECONOMICS OF COAL LIQUEFACTION
An example of process economics is included here to show a method for this type of calculation. Results obtained should be regarded as estimates based on conceptual plant designs and on a relative rather than an absolute basis.
A product-value technique was used in determining product cost from a plant with a variety of products having different properties. This technique calculates a price for a reference fuel, in this case premium gasoline, and all others are determined from this reference. The basic assumption here is that particular product prices will remain in a fixed ratio with time. Solid fuels were priced on their heating value relative to fuel oil. Fuel oil is defined as industrial No. 6 or bunker C, and No. 2 is considered the same as diesel fuel. Naph- tha is a general distillate product used for the production of gasoline, diesel, or other products. All naphtha were assigned values related to a cost of upgrading to gasoline. Liquid petroleum gas (LPG) con- sists primarily of propane and butane, and gasoline is low-octane as obtained from a simple Fischer-Tropsch process. Value factors for these products are shown in Table 9-29.
TABLE 9-29 Value Factws for Enorgy Products (Raferenco to Premium Gas&ml
‘No sales in 1978; energy price assumed as 10% less than that of fuel oil. f Premium gasoline is reference fuel; f = 1.00 tNo significant market in 1978; energy value awmed as same as premium
gasoline $No market in 1978, energy price 4% below methanol for water content. ~Severe price regulation for natural gas in 1978; energy value set at 1.00.
HEAT GENERATION
GENRUL Mars: Field, Gill, Morgan, and Hawk&y, Combustion of Cases, t&Craw-Hill, New York, 1946. Spalding, Some Fun&menials of Puloerized Cool, British Coal Utilisation Research Association, Leatherhead, Combustion, Academic, New York. 1955. Thring, The Science of Flnmes and England. 1967. Jmt and Croft. Explosions and Combustion Processes in Furnaces, Wiley, New York, 1962.
Sib!/ %&k-F.
l.ooo
Hat of am
B.t.u./cu. t
/lb. a DR
1 Nr
i3.M lb.41
At?
Il.53 n.34
COI
3.66 .
1.90 2.47 1.57
13.m
i::3 II.91
11::; I1.e.I Il.81 II.74
::I: 3.14
::::
kiti 10.53
X 13.70
3.38
::::
'!:i X
Z E 4.69 6.10
::ii I.37 1.92
::;
B&u/lb.
u. ft. combustible
Flu4 ~OdUcta Kolecu-
w&t
Lb. / cu. t.
i
I I I I I I I I I I I I I I
i
N¶
X 1.1
7.53
1::: 24.47 24.47 M.II
3:;: 35.76
El 22.59 22.59 28.23
KI 39.52
9.41
'Z 11.29 3.32
::3
N;
0.M 1.41
1.90
13.26
EE
K
ll:E 11.81 II.74
I:3 II.39 Il.39 II.39
18.22
I:::
10.22 9.97 4.98
::s
E
Gross Net
14.093 14D93 61.100 51423
4.347 4.347
23.879 22.320 21.661
::iE 21.091 21.052 20.970 2094o
$:?i 19:944 19.680
IE 19:47ll 19.3% 19.4o3
EC 19:496 19.382 19.363
3.0
:::
:::
IZ l8:65O
17.480 17.620 17.760
::?I 10.5
21.500 17.298 10.259 13.161 9.668
2.5
'::! 3.0 0.75
3.983 I.0 6.545 I.5
COI - I.0
I.0
I.0 2.0 3.0
:::
::: 5.0 6.0
:::
::: 5.0
::: 11.0
2.0
I::: 2.0
80 1.0 I.0
Grow Net Air
4.76 2.33
2.38
9.53
E:$ a.97
E:E s&II M.lI (5.26
::z
iE 55 73
:::: 50.02
II.91
'::I:
'i:F
::G
El0
0.57
::Fi
::!i
Z
:::: 3.53
3.42
::::
::::
::X 3.17
3.07
::!i 2.08 I.41
I:!!
, , 12.01 2.016 32.OOO
Z:!" 44.01
16.O4l 30.067
ai
8::: 72.144
E:I$
32.06
X6 10.016 28.9
::EE ::t:: 0.1170
::E 0.2no3
::EZ
::YE 0.0456
0.0911 0.1733
EE
‘%E 13.443
'E
KS 6.365
::::1
::iE
::ii
':G
c!i 5.400
::!i: 3.567
'::Z
'A:X 21.914
'!:Z 21.017 13.063 i
0.97Ut 1.4504 I.9336 I.9336 2.4190
325
327.
1614
SE
ZE
3751
z
hii
IZ 441
647
215
37l
1513
is
z
g
z.!
I:
596
1.0
:::
::: 5.0
:::
!:i
2.0
::: 4.0 6.0
3.0
::i
I.0
:::
:::
I.0
a.94
. . . .
:::
1:: 1.55
I:Z
I:E
I:E
I:Z 1.29
0.69
::E
E
1::: I.59
0.53
‘From American Gas Association. To convert pounds per cubic foot to kilograms per cubic meter. multiply by 16.02; to convert cubic feet per pound to cubic meters per kilogram, multiply by 0.062; to convert British thermal units per cubic foot to joules per cubic meter. multiply by 37.3 X IO’? and to convert British thermal -units per pound to joules per kilogram, multiply by 2329.
60°F and 30 inHg dry = 15.6OC and 76.2 cm. t All gas volumes corrected to 60°F and 30 inHg dry. (Carbon and sulfur are considered as gases for molal calculations only.
9-38 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
COMBUSTION STOICHIOMETRY
Theoretical Oxygen and Air for Combustion The amount of oxygen or air just sufficient to burn the carbon, net hydrogen,’ and sulfur in a fuel to carbon dioxide, water vapor, and sulfur dioxide is the theoretical oxygen or air. The general expression for combustion of a fuel is
Op = mCOp + ; He0 0
(Q-30)
m and n being the number of atoms of carbon and net hydrogen, respectively, in the fuel. For example, this relationship shows that 1 n-101 of methane (CH,) requires 2 mol of oxygen for complete com- bustion to 1 mol of carbon dioxide and 2 mol of water. If air is used, each mole of oxygen is accompanied by 3.76 mol of nitrogen.
The theoretical weight or volume of oxygen or air required to burn a given weight of a fuel is of primary interest in engineering calcu- lations for the design of equipment. The volume of theoretical oxy- gen needed to burn any fuel can be calculated from the ultimate analysis of the fuel as follows:
= ft3 oxygen/lb fuel (9-31)
where C, Hp, 02, and S are the decimal weights of these elements in 1 lb of fuel. (To convert cubic feet to cubic meters, multiply by 0.0283; to convert cubic feet per pound to cubic meters per kilogram, multiply by 0.0623.) The coefficient 359 is the volume in cubic feet of 1 mol of oxygen at O’C (32’F) and 1 atm. The weight of oxygen
‘Net hydrogen - total hydrogen - (0.125 X oxygen in fuel).
TABLE 9-3 1 Thowotical Air and CO, fov Combustion of Industrial
n . . . . . . . . . ~ 7.62-7.76
IQh-vol+lnA.. &h-mlat~LB.. ..................
. 7.%7.75
. Hi@-volat&c..
7.56-7.75 ..........
[*bb&umk.w~. 7.54-7.67
Lip .......... 7.56-7.57
ortbD&ot4.. ........... . Texas..
................................... .
. . . . . . . . . . . . .
,...,... ,..,...,
I . . . . . . . . . I 7.32-7.41
$fi&:::; :::.:::::: ::-:., I
brhuia . . . . . :i ::::::::: ..,,..,,, -__
‘From Johmn and Auth (eds.), Fuels and ~omb~.~rron McGraw-Hill, New York. 1951, p, 355. (lb/lo,000 Btu) x 43 = k,
tHigher heating value.
in pounds is obtained by multiplying cubic feet by 0.0891, the den- sity of oxygen at the same conditions. The w~lume of theoretical air is obtained by using a coefficient of 1710 instead of 359 in Eq. (Q- 31).
Table Q-30 gives the theoretical oxygen and air requirements and the gaseous products of combustion (POC) for a wide variety of corn- bustible substances.
Table Q-31 gives the theoretical air requirements on the basis of the higher heating value and the maximum, or theoretical, carbon dioxide content of the POC for several industrial fuels. The close agreement among theoretical air requirements suggests that a good approximation of the air requirements is 7.7 lb/IO,000 Btu (HHV) for coal and coke and 7.4 for petroleum oils. If only the lower heating value of the fuel is known, the HHV can be calculated from Eq. (Q- 6) or (Q-7).
Excess Air for Combustion More than the theoretical amount of air is necessary in practice to achieve complete combustion. This excess air is expressed either as a percentage of the theoretical air or as the total air divided by the theoretical air. The former is most frequently used. The latter is sometimes called the excess air num- ber. If, for example, it is 1.25, there is 2.5 percent exces air. Figure Q-30 shows the relationship of oxygen in the POC to excess air for various industrial fuels.
If it is desired to know the percentage of excess air A, under the operating conditions of a particular combustion process, it can be cal- culated from
4 = OS
0.266N* - 02 100
where 0s and N2 are the percentages by volume of these gases in the dry POC, as determined from an Orsat analysis or other volumetric methods for analyzing POC Equation (Q-32) is applicable only when the nitrogen in the fuel is negligible and there are no combustible gases, such as carlxon monoxide or hydrogen, in the POC. If these gases are present, the percentage excess air is
Op - 0.5(C + Hz) Ax = 0.266N2 - O2 + 0.5(CO + HP)
(W (Q-33)
60
0 I 2 3 4 5 6 7 6 9 IO II 12
Oryqen in flue 90s. by volume
FKI. 9-30 Relationship of oxwen in the tlue us to rxces~ air for various fuels
(Barley Meter Co.)
If only the carbon dioxide content of the POC is known,
* I
= 79oo((CCz), - COP1 CO$lOO - (CO&]
where (COP), is the maximum volume percentage of carbon dioxide obtainable in the dry POC for a given fuel, and COs is the actual percentage found in the dry PCC. Tables 9-30 and 9-31 give the values of (COP), for several fuels and other combustible substances.
Products of Combustion The products of combustion consist, in the case of solid fuels, of solid residue which may contain unburned combustible and gases previously referred to as POC.
The amount of residue will exceed the ash content of the original solid fuel by an amount equal to the unburned combustible in the residue. It may be estimated by determining the ash content of the residue.
The weight of dry gas in the POC may be calculated from
cd _ C, - C, 4(CO*) + 01 + 709 100 I 3(C4 + 0,) I (9-W
where Cd = lb dry gas/lb fuel fired, Cf and C, are the percentages by weight of carbon in the fuel and the residue respectively, and COs and 0s are the percentages by volume of these gases in the PCC. Equation (9-35) assumes hydrogen to be absent or negligible in the dry POC.
The weight of wet gas in the POC is
C, = Cd + 0.09Hp (9-36)
where G, = lb wet gas/lb fuel fired; and Hz is the total hydrogen, percent by weight, in the as-fired fuel.
ENTHALPY OF COMBUSTION PRODUCTS
Figure 9-31 gives the enthalpy of combustion products above lS&‘C (tWF). To illustrate its use, assume that a Eue gas at 1093°C (2tK0’F) contains, in percent per volume, 13.7 COs, 3.9 Op, 7.7 HpO, and 74.7 Ns. The enthalpy of the tlue gas at the specified tempera- ture would be (0.137 X 59) + (0.039 X 38) + (0.077 X 48) i- (0.747 X 38) = 41.85 Btu/ft3, or 1553 kJ/ms.
SOLID-FUELS COMBUSTION ON STOKERS AND IN SUSPENSION
There are basically two modes for burning solid fuels: in a fuel bed or in suspension. There are several variations of both modes, each suited to a particular system. Table 9-32 lists the kinds of equipment used to burn different types of solid fuels.
Fuel-Bed Firing Fuel-bed firing is accomplished with mechan- ical stokers, which are designed to achieve continuous or intermittent fuel feed, fuel ignition, proper distribution of the combustion air, free releare of the gaseous combustion products, and continuous or intermittent disposal of the unburned residue. These aims are met conventionally with three types of stokers: underfeed, crossfeed, and overfeed, which differ mainly in the relative directions of the flow of fuel and air. The principles of these types of stokers are shown schematically in Fig. 9-32, and capacities are given in Table 9-33.
Both fuel and air have the same relative direction in the under- feed stoker, which is built in single-retort and multiple-retort designs. In the single-retort, side-dump stoker, a ram pushes coal into the retort toward the end of the stoker and upward toward the tuyere blocks, where air is admitted to the bed. This type of stoker will han- dle most bituminous coals and anthracite, preferably I.9 to 5 cm (K to 2 in) and no more than 50 percent through a O.&cm (%-in) screen. Overfire air or steam lets are frequently used in the bridgewall at the end of the stoker to promote turbulence.
In the multiple-retort stoker, rams feed coal to the top of sloping grates between banks of tuyeres. Auxiliary small sloping rams per- form the same function as the pusher rods in the single retort. Air is admitted along the top of the banks of tuyeres, and on the largest units the tuyeres themselves are given a slight reciprocating action
0 400 803 1203 1603 Zoo0 2400 2803 32C0 3600 4co3
Temperature, "F
FIQ. 9-31 Heat content of various @.ses above 60°F in British thermal units per cubic fmt (to convert to kilojoules per cubic meter, multiply by 37.3). ‘T - (“F - 32) X X.
to agitate the bed further. This type of stoker operates best with cak- ing coals having a relatively high ash-softening temperature. Coal sizing is up to 5 cm (2 in) with 30 to 50 percent through a O&cm (%- in) screen.
The fuel flows at right angles to the air Bow in the crossfeed stoker. The most common of this type is the traveling-grate stoker, which is built in two types, the chain grate and the bar grate. Coal feeds by gravity into a hopper at one end of the moving grate. As the grate paws under the hopper, it carries a bed of fresh coal toward the furnace. Only a small amount of air is fed at the front of the stoker, to keep the fuel mixture rich, but as the coal moves toward the middle of the furnace, the amount of air is increased, and most of the coal is burned by the time it gets halfway down the length of the grate. Fuel-bed depth varies from 10 to 20 cm (4 to 8 in), depending on the fuel, which can be coke breeze, anthracite, or any noncoking bituminous coal.
Figure 9-33 illustrates a variation of the traveling-grate stoker, which is widely used for sintering ore. Combustion air is drawn downward through the bed of ore and coal, and combustion products are removed beneath the grate.
The fuel and air flow in opposite directions in the overfeed stoker. Except for certain types of gas producers, in which coal moves down- ward toward a grate against upward movement of the air (or oxygen and steam) through the grate, there is no combustion system that operates purely in the overfeed mode. However, the spreader stoker approximates overfeed action. A portion of the fuel burns in suspen- sion, and the remainder burns on a dump, undulating, or moving grate.
Spreader stokers with cecillating, pulsating, or traveling grates have been widely employed because they will burn all typesoT coal,
940 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TABLE 9-32 Burning Equipment for Solid Fudr
T Stokers
Fuel c Coke breeze Anthracite
Bituminous coal: 17-2796 volatile 27-352 volatile
Strongly coking
Weakly coking
E.‘Pi.
w. Va., cent. Pa.
w. Pa., w. Va., Ky., Ohm, Utah
Ind., Iowa, Ill.,
Cola., W. Ky. Pipelme slurry
Lignite
‘From Baumeister and Marks, “Standard Handbook for Mechanical Engineers,” 7th ed
good application. but there are many factors affecting the burning of fuel, and variatior equipment.
,, McGraw-Hill, 1967. Equipment indicated will usually I IS of fuel properties that guide the indiwdual selection c
t c = coarse sizes only. Aux = auxiliary fuel-coal, oil, or gas. t Bark and wood are also burned on inclined grates and in Dutch-oven pile furnaces.
respond rapidly to load changes, and operate efficiently, with com- paratively low excess air. Low gas velocities through the furnace are necessary to minimize fly-ash erosion, and dust collectors must be used to minimize dust emissions from the stack. (Since spreader firing combines the features of fuel-bed and suspension firing, the combi- nation is discussed later under “Spreader-Stoker Firing.“)
Suspension Firing Suspension firing of pulverized coal is used much more often than fuel-bed firing of coarse coal in the United States. This mode of firing coal affords higher steam-generation capacity, is independent of the caking characteristics of the coal, and responds quickly to load changes. However, pulverized-coal firing is
TABLE 9-33 Cupacitior of Mechanical Stokers
steam generation,
Type ICOO lb/h’
Maximum grate heat release, loo0
Btu/(h.fP)t
Single retort (underfeed) 5-50
Multiple retort (underfeed) 40-300 ::
Traveling (crossfeed) lo-300 300
Spreader ~overfeed) IO-300 loo0
‘To obtain kg/s, multiply by 1.26 X lo-‘.
tTo obtain J/(m*.s), multiply by 3.16.
ICI
r;rTz, Basic types of mechanical stokers. (a) Underfeed (b) Crwfeed. (c) Y FiG. 9-33 Improved sintering prcca. (Courtesy of Chemical Engineering.)
SOLID-FUELS COMBUSTION ON STORERS AND IN SUSPENSION 941
rarely used on boilers of less than 45,360 kg/h (100,000 lb/h) steam capacity, since stokers are more economical for units of lower capacity.
The various burner and furnace configurations for pulverized-coal firing are shown schematically in Fig. 9-34. The U-shaped flame, des- ignaied as fantail vertical firing (Fi-& 9-34a), was d&loped initially for pulverized coal before the advent of water-cooled furnace walls. Because a large percentage of the total combustion air is withheld from the fuel stream until it projects well down into the furnace, this type of firing is well suited for solid fuels that are difficult to ignite, such as those with less than 15 percent volatile matter. Although this configuration is no longer used in central-station power plants, it may find favor again if low-volatile chars from coal-conversion processes are used for steam generation or process heating.
Modem central stations use the other burner-furnace configura- tions shown in Fig. 9-34, in which the coal and air are mixed as rap idly as possible in and close to the burner. The primary air, used to transport the pulverized coal to the burner, comprises 10 to 20 per- cent of the total combustion air. The secondary air, comprising the remainder of the total air, mixes in the burner with the primary air and coal in a manner to promote rapid mixing. The velocity of the mixture leaving the burner must he high enough to prevent Ilashback in the primary air-coal piping. In practice, the velocity in the pri- mary air-coal pipe is maintained at about 31 m/s (100 ft/s).
RQ. P-35 Circular burner for puhwized oool, oil, or gas (From Bautiter, Marks’ Standard Handbook for Mechanical Engineers, 7th Ed.. McGraw-HIU, New York, 1967.)
being 30°. enabling the operator to control superheat and to permit selective utilizntion of furnace heat-absorbing surfaces. Basically the turbulence needed for mixing is generated in the furnace instead of in the burners.
The circular burner shown in Fig. 9-35 is widely used in horizon- tally fired furnaces and is capable of firing coal, oil, or gas in capac- ities as high as 174 GJ/h (165 million Btu/h).
In tangential firing (Fig. g-346) the burners are arranged in ver- tical banks at each comer of a square (or nearly square) furnace and
In cyclone firing (Fig. 9-34d) the coal is not pulverized but is
directed toward an imaginary circle in the center of the furnace. crushed to 4-mesh size, admitted with the primary air in a tangential
This results in the formation of a large vortex with its axis on the manner to a horizontal primary, cylindrical chamber called a
vertical centerline. The burners consist of an arrangement of slots cyclone furnace. The finer particles bum in suspension. while the
one above the other, admitting, through alternate slots, primary air- coarser ones are thrown by centrifugal force to the outer wall of the
fuel mixture and secondary air. It is possible to tilt the burners cyclone furnace. The wall surface, having a sticky coating of molten
upward or downward, the maximum inclination to the horizontal slag, retains most of the coal particles until they burn. The secondary air, which is admitted tangentially along the top of the cyclone fur-
Primary
ndary
Fantoil Multiple intertube Plan wew of furnace
(a) Vertical Fuing (b) Tonpentlal Firing
Mulhple Intertube Circular
(c) Haizontal Firing
U ond coal
(d) Cyclone Flrmq (4 Opposed -inclined Firing
RG. 9-34 Burner and furnace configurations for pulverizec-cosl firing
9-42 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
FIG. 9-36 Cyche furnace. (From Baumetster, Mark; Standard Handbook for Mechanical Engineers. 7th ed., McCrawHt11, New York, 1967.)
nace, completes the combustion of the coarse particles at a firing rate of about 18.6 GJ/(h.ms) [500,000 Btu/(h.fts)]. Slag drains continu- ously into the main boiler furnace and then into a quenching tank. Figure 9-36 shows the cyclone furnace schematically.
Spreader-Stoker Firing Spreader stokers burn coal by propel- ling it into the furnace. A portion of the coal burns in suspension (the percentage depending on the coal fineness), while the rest burns on a grate. In most units coal is pushed off a plate under the storage hopper onto revolving paddles (either overthrow or underthrow) which distribute the coal on the grate (Fig. 9-32c). The angle and speed of the paddles control coal distribution. The largest coal par- ticles travel the farthest, while the smallest ones become partially consumed during their trajectory and fall on the forward half of the grate.
A few spreaders use air to transport the coal to the furnace and distribute it, while others use mechanical means to transport the coal to a series of pneumatic jets.
The performance of spreader stokers is affected by changes in coal sizing, the main problem being the size consist of the fuel fired The equipment can distribute a wide range of fuel sizes, but it distributes each particle on the basis of the size and weight of the particle. Nor- mal size specifications call for 1.9~cm (%-in) nut and slack with not more than 30 percent less than 0.64 cm (X in).
Approximately 30 to 50 percent of the coal is burned in suspen- sion. If excessive fines are present, more coal will be burned in sus- pension, more coal particles will be carried out of the furnace, and very little ash will be available to provide a protective cover for the grate surface. If sufficient fines are not present, the capacity of the unit will be reduced because the grate is not designed to burn the entire capacity of the furnace, usually resulting in excessive live coals being dumped to the ash hopper.
The grates used with spreader stokers are of several types, as shown in Fig. 9-37. Stationary grates are the cheapest to install, but they must be divided into zones for cleaning and ash removal. In the dumping-grate stoker the grates themselves can be dumped, thereby olimhrting tlrc h&g UC a.&~>. TlrL psvvider DVIIIC: reducr~on In the
(a) Stat ionory (b) Cumpmg
(cl osclllotlnp (d) Traveling
Ao. 9-37 Types of grates used with spreader stokers.
time necessary for cleaning the grates. Continuous-cleaning grates do not need to be zoned for ash removal; the higher grate heat releases possible make such grates economical. Small units can be equipped with grates installed at a slight slope and using a vibrating or oscillating motion to propel the ash to the end of the grate. The stoker is in motion only a small portion of the time, and the fuel bed moves forward as one mass, so there is no serious intermixing of ash and burning coals. These units are restricted by the size of grate, weight of fuel bed, and physical size of the driving apparatus. Large spreader stokers are normally equipped with traveling grates.
Grate heat-release rates used in sizing spreader stokers are listed in Table Q-34. The figures given in the table are for normal designs and will vary for a particular installation, depending upon the coal used and the load factor of the particular unit.
Excess air is usually 30 to 40 percent for stationary and dumping grates, while continuous-cleaning grates are operated with from 22 to 30 percent excess air. Preheat air can be supplied for all types of grates, but the temperature is usually limited to 120 to 15O’C (250 to 300°F) to prevent any excessive slagging of the fuel bed.
Overfire air nozzles are located in the front wall underneath the spreaders and in the rear wall from 0.3 to 0.9 m (12 to 36 in) above the grate level. These nozzles use air directly from a fan or inspirate air with steam to provide turbulence above the grate for most effec- tive mixing of fuel and air. They supply about 15 percent of the total combustion air.
The size range of spreader stokers extends into that for which mul- tiple-fuel firing is generally considered necessary. It is usually easy to increase the height of the furnace and install oil or gas burners in the upper portions of the furnace. During firing of this auxiliary fuel
TARE 9-34 Grate Hoat Relwses in Sproadr Stokm
Grate heat release 1000 B.t.u./(hr.)(sq. ft.)
Without dust Grate type collector With dust collector
For bituminous coals
Stationary: Maximum continuous load 350 2.hr. peak 400
Dumping: 375 450
400 450
Maximum continuous load 2-hr. peak
Oscillating: Maximum continuous load 2-hr. peak 1
Travel& 1000 Ib./hr. continuous boiler
475 525
555 62.5
loo 200 300 axl 7lJlJ 7z.5
725 775 800
Stationary: Maximum continuous load 2-hr. peak
Dumping: Maximum continuous load 2-hr. peak
Oscillatinn: Maxi&m continuous load
Matimum continuous load
2.hr. peak Trawling:
loo0 Ib./hr. continuous boiler capacity
Maximum continuous load 2-hr. peak
For Iowa coal, subbituminous coal. lignite. wood. and bagasse
6.50 Refractory with clinker chill
700 Water-cooled furnace
800 All furnaces
loo 200 300 150 850 850 850 9001ooo
NOTE: To convert British thermal units per hour-square toot to joules per square meter-second. multiply by 3.16.
SOLID-FUELS COMBUSTION IN FUJIMZED BEDS 943
TABLE 9-35 Factors for Selecting Mechanical Stokers
Chain or FaCtOrS trawling grate Spreader Underfeed
Initial capital investment Handling fine coal Handling caking coal Handling ash Maintenance and operating costs
Fly ash and carbon loss Draft loss through fuel bed Minimum exees air, percent Ability to handle load changer
Least Least Most POX POOr PCOr PO01 Good PO01 Good Excellent Fair Intermediate Lowest Largest
Lowest Largest Lawest Intermediate Lowest Largest 30 2.5 45 Fair Excellent Fair
the grate must be protected from overheating by a very deep bed of ash or a firebrick cover, both with slight air leakages.
The carbon content of the ash passing out of the furnace varies from 30 to 50 percent. Overall efficiency of a spreader stoker can be increased by rebuming this fly ash. It is returned to the stoker grate by a gravity or pneumatic feed system. The reinjected ash must be retained on the fuel bed to keep the fly-ash loading in the boiler passes low.
Table 9-35 shows some of the factors for selecting mechanical stokers.
Pulverizers The heart of any solid-fuel suspension-firing system is the pulverizer. Air is used to dry the coal, transport it through the pulverizer, classify it, and transport the specified fines to the burner, where the transport air provides part of the air for combustion. The pulverizers themselves are classified according to whether they oper- ate under positive or negative pressure and whether they are slow-, medium-, or high-speed.
Pulverization occurs by impact, attrition, or crushing. The capac- ity of a pulverizer depends on the grindability of the coal and the fineness desired, as shown by Fig. 9-38. Capacity can also be affected by excessive moisture in the coal. Capacity can be restored by increasing the temperature of the primary air; Fig. 9-39 indicates the temperatures needed. For pulverized coal-fired boilers, the coal size usually is 65 to 80 percent through a 200-mesh screen, which is equivalent to 74 pm. The kinds of pulverizers and their characteris- tics are discussed in Sec. 8.
o.23~ 70 00 90 100 Grlndablllty index,A.S.T.hl.
FIG. 9-38 Variation of pulveriser capacity with the grindability of the coal and the fineness to which the coal is ground (Bobcock G Wtlcox Co.)
loo’ ’ ’ ’ ’ ’ ’ ’ ’ ’ J 2 3 4 5 6
Lb. air/lb. coal pulvermd
FIG. 9-39 Effect of moisture in coal on pulveriser capacity. Sufficient drying can be accomplished to restore capacity if air temperatures are high enough. (Combustion Engineer, Combusifon Engtneertng Inc.. New York, 1966.)
SOUD-FUELS COMBUSTION IN FLUIDIZED BEDS
GENERUREPOIMCES: Proceedtnns of the Fourth IntemattomaI Conference - , on Flutdtzed-Bed Combwtton, De. Q-11, 1975, The MITRE Corporation, McLean. Va. 22102. Pmceedtngs of the Workshop on Uttltty/lndu.strtal Implementation of Flutdtzed Bed-Comtwtton Systems, Atlanta, Ga., Apr. 27-28, 1976, The MITRE Corporation. McLean, Va. 22102. Pmceedtnga of the Flutdtzed-Bed Cm&&ton Technology Exchange Workshop, Apr. 13-15, 1977. The MITRE Cormration. McLean. Va. 22102. Proceedtnns of the Ftfth Inter&tonal Confer& on ‘Flutitzeed-Bed Combustton, D&&&r 1677, The MITRE Corporation, McLean, Va. 22102. An Assessment of the Status of Flutdtzed-Bed Ccmbwtron Based on the Papers of the Ftfth btemattonul Conference. December 1979, The MITRE Corwration, McLean. Va. 22102. Prcieedags of the Sixth Intematkmal Conf&m on Flutdtzed-Bed Corn- bustton, Atlanta, Ga., Apr. Q-11, 1960, U.S. Department of Energy, CdNF- KlO428, vols. 1-3.
Atmospheric and Pressurized Fluidized Beds (AFBC and PFBC) Fluidized-bed combustion (FBC) involves the combustion of fuel in a bed of solid particles, which is tluidized (held in suspen- sion) by the injection of air at the bottom of the bed. When coal is burned in this manner, the bed can consist of inert solids, coal ash, or a sorbent such as limestone or dolomite. Limestone or dolomite in the bed reacts with the sulfur dioxide formed during combustion of the coal and forms a solid sulfate which can be discarded as a dry solid. Variations in the technology include atmospheric-pressure tlu- id&d-bed combustion (AFBC) and pressurized tluidized-bed com- bustion (PFBC). Figure 9-40 shows various applications of AFBC, and Fig. 9-41 shows PFBC-cycle concepts.
In the early 196Os, Great Britain’s National Coal Board, the British Coal Utilisation Research Association, and the Central Electricity Generating Board began investigating FBC. After the energy crisis in 1973, AFBC and PFBC of coal developed rapidly, mostly in the United States, Great Britain, and the Federal Republic of Germany, for use in utilities, process industries, and the institutional sectors. FBC has great potential to burn efficiently and cleanly a wide variety of fuels, ranging from high-sulfur, high-ash c&s of all ranks and grades to industrial-process wastes and municipal sludges.
Some of the potential advantages of FBC, compared with pulver- i&-coal firing, are:
1. Less sulfur dioxide emissions, because much of the sulfur is captured by fuel-bed additives such as limestone or dolomite
Feed water inlet
Saturoted- steam outlet
Feedwoter inlet +
Hot gases
for process needs
Fluldized bed Fluidized bed Fuel and
C - sarbent Working inlet
fluid ‘- ------- ------- Air Inlet Inlet *_ (fluidizing
FIG. 941 Prffsurized-Eutdized-bed-combustion concepts. (a) Steam-cc&d tuber in bed (b) Air-cooled tubes in
bed CC) Bed cooled by excess air (300 percent); no in-bed tubes.
946 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
XK’
RQ. 943 Carbon-combwtion efficiency as P function of bed temperature.
75 -
70-" " " " " ' I 0 1 2 3 4 5 6 7 6 9 10 1112
Gas velocity. If/s
Ro. 944 Carbon-combustion efficiency as B function of gas velocity.
11 I I J 0 5 10
Gas vekmty, o/s
~NX 9-45 Dependency of bed grid area on gas velocity.
2 3 4 5 6
CO/S
FIG. 946 Calcium-sulfur-ratio effect on SO* capture
The relationship of bed area to velocity is illustrated in Fig. 9-45. Decreasing velocity rapidly increases the required square feet of grid or bed area needed per unit of output.
SOs Removal SOs removal or S retention in situ is a unique fea- ture of the AFBC process. Sulfur contained in the fuel is oxidized to Sop during the combustion process. This SO, chemically reacts, in the presence of oxygen, with the sorbent to form a stable, solid sulfate in the bed. SOs emissions are thereby controlled in the combustion vessel itself, eliminating the need for downstream SOa cleanup of the Eue gas.
Sulfur capture depends on a number of design and operating vari- ables as well as on the sorbent used. A primary variable, which can be readily controlled, is the calcium-tosulfur mole ratio. Also of importance is the bed temperature, since the SOs-sorbent reaction is temperature-dependent. These two effects are illustrated in Fig. Q- 46. Typical experimental trends are shown for SOa capture plotted against the Ca/S ratio for several bed temperatures. An optimum sulfur-capture temperature of around 643% (1550OF) is common for many sorbents. Increasing the Ca/S mole ratio increases sulfur capture, but it is desirable to minimize calcium addition because this represents greater sorbent costs, parasitic heat loss through calcina- tion, and increased disposal problems.
Other variables that affect sulfur capture include bed depth and gas velocity. Deeper beds allow longer gas residence time, i.e., pro- vide more contact time with the sorbent, and thereby increase sulfur capture. Low velocity also increases gas residence time and, there- fore, increases sulfur capture. These variables along with the Ca/S ratio can be balanced to achieve efficiency of sulfur capture. Fig. Q- 47 presents calculated curves which illustrate this sulfur-capture trade-off. In this figure, two curves are shown, with sulfur-removal efficiency plotted versus the Ca/S ratio. In curve A, the performance of a low-velocity bed (4 ft/s) shows high sulfur capture at relatively low velocity. Curve B shows that high Ca/S ratios are needed for high sulfur capture at higher bed velocities.
Heat Transfer Heat-transfer rates to tubes immersed in AFBCs are higher than those to tubes in conventional pulverized-coal-fired boilers. This feature of AFBCs allows relatively high volumetric heat release and absorption rates, which result in relatively small boilers. The heat-transfer rate depends on the bed particle size as shown in Fig. 9-48. Bed particle size, however, is largely a dependent variable in a given design and is not readily controlled or changed. Bed-par- title-size distribution depends on sorbent and fuel-feed size, sorbent- attrition rate, carry-over rates, and fuel-ash properties. The heat- transfer rate is nearly independent of gas velocity in the AFBC, provided the velocity is above the point for minimum Euidiaation.
Nitrogen Oxidea Emissions Emissions of nitrogen oxides are limited by current New Source Performance Standards (NSPS) to less than 0.7 lb NOa/lOa Btu. In the AFBC bed, combustion occurs at relatively low temperatures [760 to 930% (1400 to 1700°F)], com- pared with the much higher temperatures typical of pulverized-coal-
SOW-FUELS COMBUSTION IN FUJIDIZED BEDS 9-47
fired boilers. These low temperatures do not allow significant oxida- tion of atmospheric nitrogen, so the AFBC process is characterixed by low NO, emissions. Nitrogen oxides formation in the AFBC results primarily from oxidation of fuel-bound nitrogen. The reaction of carbon monoxide and NO, in the gas-burnout zone apparently further reduces NO. emission from the AFBC. Fuel nitrogen content and percent of excess oxygen are the two main variables affecting NO, emission. Over the excess-oxygen range of 0 to 10 percent, NO. emissions are generally below the current NSPS level as well as the proposed level of 0.6 lb NOs/l@ Btu.
Experimental data on NO. emissions taken since the late 1966s from major FBC experimental facilities are shown in Fig. Q-49. Superimposed on the graph are three levels of emission control: mod- erate, intermediate, and stringent. These three levels are those that
Average diameter, pm 500 loo0 Preswre. kPa 101 101 Bed OC temperature, 840 840 Excess air, percent 20 20 Velocity, m/s Bed depth. m
1.38 3.scl 1.22 1.22
PI@. 9-47 Sulfur-capture tradeoff
OW4 001 004 01
Portlcle we. 8"
FIG. 9-U Effect of Particle size on bad-totute heat transfer.
Boiler capocity, MW,
Ao. 949 NO, emissions from AFBC facilities.
can be achieved by (1) normal or routine operation, (2) a well-main- tained system operating with some optimixation of design conditions, and (3) optimixation of all design parameters so that the system is performing at its technological limit.
Figure 9-49 shows that as AFBC systems increase in size, the range of NO. emissions decreases. When capacities approach those expected for commercial use (Le., greater than 5 to 10 MWt), the range of NO, emissions falls below even the most stringent levels identified for possible emission standards.
Fluidization Design Factors In addition to the AFBC process considerations, the design of an AFBC combustor must follow the design principles associated with fluidixation as discussed in Sec. 20: “Fluidized-Bed Systems.” Information useful in the design of coal- fired AFBCs is presented in the following paragraphs. The infor- mation is based on the Coal Conoersfa Systems Data Book, pre- pared by the Institute of Gas Technology for the U.S. Department of Energy (HCP/T2266-01).
Shape Factorr of Variour Mater&& Shape factors for non- spherical particles are often required in tluidiaation studies. Shape factor rj~ is defined as the ratio of the area of a sphere, with a volume equivalent to that of the particles, divided by the actual surface area of the particles. Some values follow:
Relation of Minimum Fluidized-Bed Voidage to Average Par- ticle Diameter Minimum iluidized-bed voidage c,,, is often required in tluidization studies. Fig. 950 gives c,,,, as a unction of t’ particle diameter for various materials.
Minimum Fluidizafion Velocity The Kunii-Levenspiel corre- lation is recommended for estimating minimum fluidization velocities.
(Q-37)
where Re,,,) =
Ar =
B= hf =
Pa =
Dp,u,1_ - Reynolds number at minimum fluidi- c1 ration velocity
@&” - ps)g = Archimedes number Ir s
shape factor minimum fluidized-bed voidage particle density of fluidizing solids, lb/f?
9-48 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
D, = average particle diameter, ft ps = density of fluidizing gas, lb/f?
U mf = minimum fluidization velocity, ft/s or = viscosity of fluidizing gas, Ib/(ft.s) g = acceleration of gravity, 32.2 ft/s*
When reliable values of shape factor and voidage at minimum flu- ‘idization velocity are not available, the following correlation is useful:
(To convert pounds per cubic foot to kilograms per cubic meter, mul- tiply by 16.02; to convert feet per second to centimeters per second, multiply by 30.48.)
Bed Expansion on Fluidization The following equations are recommended: For Dw 5 2.5 in,
4=1+ 0.762(U - U,,,,)“s70p~oB3
L p~wyv~o.445 (9-39)
mf
and for Du > 2.5 in,
& = 1 + 10.978(U - Umf)0738D;oo6p~376
Ld p3? om
mf Ps (9-40)
where & = column diameter, ft L = height of minimum tluidized bed, ft
.$ = height of tluidized bed, ft U = superficial gas velocity, ft/s
U,,,f = minimum Buidization velocity, ft/s p, = particle density of fluidizing solids, lb/f? pg = density of fluidizing gas, lb/f? D, = average particle diameter, ft = l/[C(X,/D )]
The experimental data on which the correlation is b &are lim- ited to a maximum bed diameter of 1 ft. Extrapolations to very large bed diameters must be made with caution. Second, the correlations in their present form do not account for the fact that there would be
I I
0 0.015 0.020 0.1
DP, in
5
FIG. 9-50 Relation of minimum fluid&d-bed voidage to average particle diameter. .
no bed (infinite expansion) at superficial gas velocities equal to or greater than the terminal velocity of the particles. Superficial veloc- ities in the data used are less than 60 percent of the terminal velocity for the average particle diameter for the bed. Projections to higher relative velocities should be made cautiously.
hnsporf Disengagement Height (TDH) Fluidized beds are usually operated with a wide size distribution of solids, containing a substantial portion of fines. More fines are also created by attrition and by virtue of reacting solids, and the exiting gases may exceed the terminal velocity of many of these fine particles, thereby carrying them out of the reactor. In addition to the entrainment of fines, solids are carried into the freeboard by erupting bubbles. However, as the particles ascending the freeboard space lose their kinetic energy, some particles will return to the bed, depending on particle size and particle density. As a result, particle loading in the escaping free- board gas drops rapidly to a certain point beyond which it attains a constant value at which the terminal velocity of the accompanying particles is close to or less than the velocity of the exiting gas stream. The freeboard height corresponding to the constant entrainment rate is known as the transport disengagement height (TDH), which determines the optimum distance for gas exit ports above a fluidized bed. TDH is discussed in Sec. 20: “Fluidized-Bed Systems.”
AFBC Design Options The effects of major design and operat- ing variables on AFBC performance characteristics were presented in the preceding subsection. However, technical parameters should be selected only after consideration of economic and site-specific fac- tors. Some of the factors to be considered are:
1. Availability and costs of fuel and sorbent 2. Fuel and sorbent tlexibility (reliability of sources) 3. Space available for AFBC system 4. Space available for solids receiving, preparation, and storage 5. Local environmental regulations 6. Impacts of energy costs on product costs (energy intensiveness
of application or process) 7. Load-following requirements compared with load-following
capability of the AFBC system
COMBUSTION OF LIQUID FUELS
Burners for Liquid Fuels For combustion, liquid fuels are vaporized or atomized in the combustion air. Distillate fuel oil can be burned with a blue flame if it is completely vaporized and homo- geneously dispersed in the air before burning. Blue-flame combus- tion is a two-step mechanism, the first step being hydroxylation of the fuel. Yellow flame indicates glowing carbon from fuel pyrolysis in oxygen-deficient parts of the Eame. Droplets of fuel may be partly volatilized, leaving the residue to decompose and burn as coke par- ticles. Either a blue or a yellow Eame may be preferred, depending on the need for conductive versus radiant heat transfer. Both types can give complete combustion if the flame is not quenched prema- turely. Time, temperature, and turbulence are the criteria for good combustion.
In vaporizing burners, reflected heat continually converts liquid fuel into vapor, sustaining the flame. This principle is used in blow- torches, pot-type home-heating furnaces, and all wick burners such as kerosine lamps, stoves, and cigarette lighters. Gasoline-burning mantle-type lamps and catalytic heaters use a more volatile fuel plus a catalytic surface to promote rapid combustion. Vaporizing burners are built in capacities up to 30 to 40 dms fuel/h and are designed for kerosine, naphtha, No. 1 fuel oil, gasoline, etc. (No. 1 fuel oil cannot be used in pressure-type vaporizing burners because of exces- sive carbonaceous deposits in the vaporizing tube)
Atomizing oil burners spray fuel at pressures of 0.69 to 2.1 MPa (100 to 300 Ibf/in’) or atomize it with air or steam at pressures of 0.003 to 1.4 MPa (0.5 to 200 Ibf/in’). Several types are shown in Fig. 9-51. Quantities of power and steam or compressed air required are shown in Table 9-36.
Combustion air is blown into the furnace with the fuel spray. Vanes and baffles are built into the air stream to assure proper air- fuel mixing. The air-handling parts, the fuel-spray pattern, and the furnace shape are matched to avoid tlame impingement, a cause of
COMBUSTION OF LIQUID FUELS 9-49
90”
FIG. 9-51 Principal types of oil burners. (a) Pressure-type vaporizing burner; oil travels through coil of pipe. Uses kerosine or gasoline, 0.1 to 6 gal/h at 5- to 5&lbf/in* fuel pressure, with B turndown ratio of 3:l. For blowtorches, lamps, and portable torch-type burner equipment. (b) High-pressure steam- or air-atomizing burner, injector or venturi type. Uses all grades of oil, No. 1 to No. 6, with heavy oil heated to flow. Oil pressure, low; steam pressure, 40 to 175 Ibf/in’. Uses 5 to 10 percent of air or 2 to 4 lb of steam for atomizing. On boilers, 2 percent of the steam output is wed for atomisation. Steam helps heat oil and assists in combustion to reduce soot. (c) Horizontal rotary-cup atomising oil burner. Uses any grade of fuel, No. 1 to No. 6. Heavy oil must be heated to 150 to 330 SSU. Oil pressure, low; air pressure, 0.25 to 3 Ibf/in*. Turndown ratio of 5:l. Capacities of 1 to 2.50 gal/h. For use on automatic-fired boilers. (d) Low-pressure air-atomizing burner, var- iable-pressure type. Uses all grades of oil, No. 1 to No. 6. when supplied at viscosity of 60 to 90 !XJ. Oil pressure, 5 to 20 Ibf/in*; air pressure, 0.5 to 5 lbf/in*. P nmary air pressure. constant; secondary air pressure varies. Turndown ratio of 4:l. Capacity of 1 to 200 gal/h. (e) M ec h anical or oil-pressure atomizing burner, return-flow type, showing general operating principle and typical design. Uses all grades of fuel oil, No. 1 to No. 6. with heavv oil heated to 150 SSU. Oil oressure. 300 Ibf/i& air oressure. low or natural draft. Turndown ratio bf 10: 1. C&cities of 10 to loo0 gal/h: cf) Complete &&&al or oil-pressure atomizing burner unit. Air supplied by natural draft of low-pressure blower. Used on boilers and rotary kilns Domestic burnen of this type use oil at lwlbf/in* pressure. (Hauck hffg. Co.)
soot or hard-carbon deposits and/or refractory spalling, washout, or slagging. Except in small domestic furnaces, oil spray and air usually enter the furnace through an ignition tile. The tile configuration, matched with the oil-spray pattern, stabilizes the flame. Furnace vol- ume is established to allow time for complete combustion. Heat- release rates depend on fuel properties, excess-air concentration, air- fuel mixing, and allowable smoke levels.
TABLE 9-36 CompresawLAir, Steam, and Power Requirements foe Atomiring Burners
Coal- and shale-derived liquids generally contain more nitrogen than petroleum and form more NO, when burned. Also the high C/ H ratio in coal-derived liquids gives luminous flames and potentially more smoke. Combustion modifications are being developed to con- trol stack emissions without requiring drastic upgrading of the fuel.
Staged combustion involves primary burning with insufficient air (to prevent NO, formation in the highest temperature zone), fol- lowed by the introduction of more air to complete combustion. In multiburner boilers, this may be accomplished by firing some burn- ers rich and others lean. (See KVB, Inc., “Reference Guideline for Industrial Boiler Manufacturers to Control Pollution with Combus- tion Modification,” EPA 600/8-77-0@3b, November 1977.)
For gas turbines, staged combustion in each burner is a promising prospect. See Fig. 9-52.
High-intensity burners permit clean combustion at low excess-air levels through finer fuel atomization and better air-oil mixing. Fig- ure 9-53 shows nozzles in which oil is sprayed through a gas, steam, or air whistle and atomized by sonic energy. Typical oil pressure might be below 0.4 MPa (60 Ibf/in’); atomizing air or steam, at 0.34 to 0.4 MPa (50 to 60 Ibf/in*); windbox (combustion air), at 0.025 to 2.5 kPa (0.1 to 10 in water).
9-50 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Quick quench slots
for dilution air
Ro. 9-52 Rich-lean-burner concept for liquid fuel with bound nitrogen. (Adapted from Pierce, Mash, and Smith, Advanced Combustion Systems for Stationary Gas Turbine Engines, 001. II: Bench Scale Evaluation, EPABOO/7- 80417b.)
Combustion Deposits Residual fuels cost less and yield more heat per gallon than distillates, but they usually have higher sulfur content plus ash-forming ingredients. In and near the combustion zone, molten ash can cause corrosion and deposits; in areas below 160°C (350°F), water and sulfur compounds in flue gas condense into corrceive acid solutions.
During combustion, the ash-forming materials oxidise and interact to form a variety of compounds. If they solidify before striking a solid surface, ash particles are likely to paas through the equipment. However, parts of a boiler (or gas turbine or diesel engine) which operate above the ash fusion temperature may accumulate deposits
Resonator chamber
onicenergy core
Sonicore Fuel Nozzles
Sonic Energy Combustion Systems,
Wilmington, Delaware
Swirl
Vortimetric atomiser
Gulf Canada Ltd., R&D Dept.
Sheridry Park, Ontario
ASME Paper 71.WA/Fu.3
Ao. 9-S) Sonic fuel nobles. oil is sheared by pressure waves of sonic fre. quency in a stream of air. gas, or steam. (a) Sonicore fuel nozzle. (Sonic Energy CombutrOn &Ma, Wlfm(ngtcm, Def.) (b) Vortimetric atomirer. (R&D %nZflmmt, Gulf hwda Limfted, Sheridan Park, Ont., ASME Pap. 71- WA/FuS.)
and suffer catastrophic corrosion. Molten vanadium compounds are particularly corrosive.
Combustion air often carries dust. A classical example in limestone areas is the diopside formed in the flame by limestone and silica dust and deposited on refractories as a glass. Spalling occurs when the furnace cools because diopside and refractory shrink at different rates.
Ashes are mixtures, and fusion is not sharply defined. Final liq- uefaction may occur at 160 to 125’YZ higher than initial sintering. VsOs melts at 673“C (1243“F), but oil-ash fusion temperatures range from below 540 to over 1995’C (1999 to 2ooO°F), depending on relative concentrations of tluxes (principally sodium) and refrac- tory compounds (such as silica, magnesia, and alumina). Vanadium corrosion usually occurs above 675°C (1250’F), and sulfidation (attack of nickel alloys by sulfates) above 999“C (1650OF).
Magnesia, epsom salts, and other compounds are added at Mg/V weight ratios of 3: 1 or 3.5: 1 to prevent corrosion and dewsition bv raising the ash fusion temperature. There is disagreement over the value of alumina as a coadditive to overcome the slight tendency of magnesia to form deposits. Calcium compounds are considered undesirable because they form hard, adherent, insoluble deposits. Manganese compounds and sometimes lead and copper compounds are used as combustion catalysts to reduce soot and smoke. There are also many additives sold to benefit the fuel-handling system. These may contain solvents or dispersants to combat sludge, emulsifiers or demulsifiers for water in the fuel, corrosion inhibitors, and other functional ingredients. Fuel suppliers should be consulted for possi- ble adverse reactions between the additive and fuel, and claims for the additive should be evaluated cautiously, but their potential use- fulness for specific problems should not be overlooked.
COMBUSTION OF GASEOUS FUELS
Combustion of gas takes place in two ways, depending upon when gas and air are mixed. When gas and air are mixed befMe ignition, as in a bunsen burner, burning proceeds by hydroxylation. The hydrocarbons and oxygen form hydroxylated compounds which become aldehydes; the addition of heat and additional oxygen breaks down the aldehydes to Hs, CO, COs, and HsO. As carbon is con- verted to aldehydes in the initial stages of mixing, no soot can be developed even if the flame is quenched
“Cracking” occurs when oxygen is added to hydrocarbons after they have been heated, decomposing the hydrocarbons into carbon and hydrogen, which, when combined with sufficient oxygen, form COs and HsO. Soot and carbon black are formed if insufficient oxy- gen is present or if the combustion process is arrested before completion.
Gas Burners A gas burner is primarily a proportioner and mix- ing device. In industrial furnaces in which long, “lazy” flames are essential, slow and gradual mixing of air and gas is necessary. When a short, bushy Rame is needed, the burner should be designed to achieve rapid and thorough mixing of air and gas. Figure 9-54 illus-
(8) fbl
Ao. 9-54 Schematia of gas-burner principles.
COMBUSTION OF GASEOUS FUELS 9-51
J&- -Gas fine , Shuiter
Gas valve / /Spud holder
/ 1 Burner body
Wnll posting I ’ /‘Nozr/e j I! 1 , I \ruunnel\
~///...,. \
f//f’ Burner cement’
Ro. 9-55 Atmospheric industrial gas-burner installation with individual air control to each burner.
trates simply the principles of gas burners. In burner A, the gas enters the furnace through a burner port and induces a flow of air through the port. Mixing is poor, and a long tlame results. The flame can be shortened with a ring burner B, in which gas Rows through an annu- lar ring and induces air Bow both around and within the annulus of gas. When both air and gas are under pressure, burner C may be used.
In each of these burners, the gas must flow through the port into the furnace at a velocity high enough to prevent the flame from burning back (flashback) into the burner. Burner shapes and arrange- ments should avoid tlame impingement on furnace walls or heat- transfer surfaces. Variations of these principles are found in com- mercially available burners such as the following.
Premix burners burn by hydroxylation and are used for many nat- ural-draft applications when accurate furnace conditions must be maintained. Figure 9-55 indicates a common natural-draft indus- trial-type burner with air being aspirated at the spud and burner throat. Figure 9-56 shows another type of premix burner, in which high-pressure air is used to aspirate the gas. The governor diaphragm controls the amount of gas admitted to the aspirator.
Governor dlaphram
Gas mlel
FKI. 9-56 Premix burner in which a proportional mixer uses air velocity to draw in a measured amount of gas. (Surface Combustta Dtv~~(on. Midland- Raps Corp.)
RQ. 9-57 Carburetor for maintaining B preset ratio of gas and air over a wide load range. adjusting to the total volume handled. (C. hf. Kemp Mfg. Co.)
Burners used for close air control, such as for generating inert gas, must exercise close control over both the fuel and the air admitted to the burners. Figure 9-57 shows a typical carburetor arrangement used for this control. The high-velocity burner shown in Figure 9-58 can be adapted for use with various gaseous fuels. Although it is not strictly a premix burner, its temperatures and mixing produce results similar to those of premix burners.
The rate of llame propagation must be exceeded in premix burn- ers to assure that ignition cannot travel back into the burner. Figure 9-59 indicates the rate of flame propagation at various air-gas ratios for several gases.
Air
M. 9-58 High-velocity burner. High heat release produces combustion results similar to hydroxylation. (?%ermal Research and Engfneerlng Co.)
9-52 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Ro. 9-59 Flame velocities of various gas-air mixtures Data on individual gases from Bur. Stand. .I. Res., 17,7-43 (1936); data on natural gas, coke-oven gas, and carbureted water gas from Combustion, American Gas Association, 1932. (As compiled by EIIiotf and Denues, U.S. Bureau of Mines, for Marks, Mechanical Engineers’ Handbook, McGrawHUl, New Y&, 1941.)
Nozzle-mix burners mix air and gas at the burner tile. As shown in Fig. 9-60, these burners can take four arrangements. The burner may be a standard forced-draft register with the gas emitted from holes drilled in the end of a supply pipe This type is easy to build, but large holes are used and gas mixing becomes a problem; these burners frequently produce a luminous gas flame. Small-diameter pipe can be inserted at the center of the burner, or large-diameter
register
(a) Blunt Pipe
rings can extend to the outside of the burner tile. These rings use very small holes and give better dispersion of gas in the air, though they can plug up easily. One burner has a spider in the burner inlet through which gas is emitted in all the several radial arms. The spi- der is drilled to emit gas from the sides of the bars to provide a reac- tion from the emission of high-pressure gas, causing the spider to turn. The spider can be attached to a fan so that forced draft is pro- vided by the movement of the spider. The spider arrangement pro- vides high turbulence for the close regulation of excess air.
Control of gas burners is accomplished by regulating only the flow of gas in aspirating burners or by regulating both gas and air flows when these are controlled separately.
Combustion Characteristics of Low- and Medium-Btu Gases Low-energy gas from various coal-gasification procqs is a source of clean fuel for utilities, industrial boilers, and industrial processes. The combustion characteristics of low-Btu gas (LBG) and medium- Btu gas (MGB) can best be desqibed by comparison with natural gas. Combustion characteristics for comparison include oxygen or air requirements, flue-gas Bow rates, tlame temperatures, and flue-gas composition, including pollutant emissions. All these factors bear on the interchangeability of LBC and MBC in the context of flame characteristics and stability. Results of experiments by the Institute of Gas Technology’ on utility-type burners and industrial burners follow.
Table 9-37 shows adiabatic flame temperatures calculated for nat- ural gas and manufactured gases. MBGs have adiabatic flame tem- peratures near that of natural gas. Adiabatic flame temperatures for LBGs are lower than that of natural gas, owing to the nitrogen in the air and fuel. The lower flame temperatures will result in lower heat- transfer rates per unit load surface area in radiant furnaces.
Figure 9-61 shows that for a given tlue-gas temperature signifi- cantly less heat is available from the tlame of a low-Btu gas than from the flame of a fuel gas from a medium-Btu gasifier or natural gas.
‘GA C~n~r~ion System Technical Data Book, Institute of Gas Technol- ogy, Chicago, November 1980.
lgnltl tube
w
GOS
WPP
(bl Small Rmg Al,
Gas suPPlY
(d) Turbme
FIG. P-60 Various ways of mixing gas and air at the burner.
COMBUSTION OF GASEOUS FUELS 9-53
TABLE 9-37 Typical Properties of Cleaned Manufactured Gases
Natural Koppers-Totzek bws oxwen
MBGs
Lurgi oxygen
Winkler Wellman-Galusha 0XYE.e” oxygen
LBGs
Wellman-Calusha air
Winkler air
Composition, 5% CH4 CO Con HZ Hz0 NZ GH6 GHs Who
Higher heating value. Btu/scf Specific gravity (calculated) Adiabatic flame temperature, OF (stoichiometric)
‘Small amounts may be present after cleaning procews tHigher heating value/(specific gravity)“*. NOTE To convert British thermal units per standard cubic foot to kilocalories per cubic meter (15°C saturated), multiply by 8.98; OC = (OF - 32) X %
For example, if furnaces fired by MBG from a Koppers-Totzek oxy- gen-blown generator (KTO) and by LBG from a Wellman-Galusha air-blown generator (WGA) each had an exit flue-gas temperature of 1316% (2400°F), the KTO-fired furnace would be losing approxi- mately 74 percent.
Conversely, for a given percentage of the input enthalpy to be transferred in the furnace, flue gas from LGB would have to be dis- charged from the furnace at a significantly lower temperature. For example, to have 30 percent of the input enthalpy available in the furnace, the WGA fuel gases would have to be cooled to 1099V (2010°F), while the KTO fuel gases could be discharged at 1543% (2810OF).
Table 9-38 shows the combustion air required and volume of corn- bustion products per 1000 Btu of manufactured gases and natural gas. Manufactured gases require slightly less combustion air than nat- ural gas, and air blowers and air ducts sized for natural-gas operation will be more than adequate for LBG.
The larger gas volumes required for a given Btu input for MBG and LBG will make gas piping, pressure regulators, and control valves undersized for most conversions. The combustion-product
Bows for low-Btu gases are considerably larger than for natural gas. This requires larger tlues, stacks, and induced-draft fans.
Table 9-38 also gives the flammability limits calculated by the method given in the Gus Engineers Handbook (1977). The values were calculated by using the fuel-gas compositions in Table 9-37. These calculated limits of tlammability are approximate values only. Accurate flammability predictions require that the fuel in question be subjected to experimental measurement.
Experimental Evaluations of LBG and MBG Research pro- grams have provided information on utilizing manufactured gases in the following areas:
I. In industrial-process burners designated for natural gas 2. As utility boiler fuel 3. Pollutant emission The results of these investigations may be summarized as follows: 1. When used in burners designated for natural gas, manufac-
tured MBG generally produce stable flames and give thermal per- formance, flame temperature, and heat-transfer rates similar to those of natural-gas flames. Flame lengths may be longer or shorter, depending on the exact burner design.
2. When used in natural-gas burners, manufactured LBG may need enlarged fuel nozzles, continuous piloting, or downrating to prevent blowoff. They give reduced flame temperatures and heat- transfer rates compared with natural-gas flames in the same furnace. Preheating the fuel and/or combustion air can increase flame tem- peratures and heat-transfer rates but would then require specially designed burner equipment with refractory linings and very large fuel low passages.
3. Using hot manufactured gases directly from the gasifier, with- out cleanup to avoid loss of the sensible heat, can produce NO, and SO. emissions greatly above those for cleaned fuels or natural gas.
ELECTRIC HEATING
Industrial electric heating can be divided into three basic categories: resistance heating, both direct and indirect; induction heating; and dielectric heating. The choice of which method to use depends on many factors. Resistance heating is the generation of heat by Joule’s law, that is, PR I- in relatively conducting materials by passing current through them by direct contact. Induction heating is also fR heating, but the current is induced in the conductor by placing it in an alternating magnetic field. Dielectric heating is the generation of heat in a nonconductor by placing it in an alternating electric field, with the mechanisms of heating being primarily dipole rotation losses. A discussion of laser heating is also included in this analysis because it is powered by electric energy. This is not an in-depth anal- ysis but a guide to making choices. For further study see Brown, Hoyler, and Bierworth, Radfo Frequency Heatfng, Van Nostrand, New York, 1947; Copson, Microuwe Heatfng, AVI Publishing Co., Westport, Corm., 1962; and Davies and Simpson, Induction Heattng Handbook, McGraw-Hill, London, 1979.
The applications for electric heating are many. In general, direct-
resistance heating is most often used for heating metal rods and bil- lets prior to rolling or forging, for melting glass in combination with other heat, in boilers for hot water, and for heating salt baths for the heat treatment of metals. Indirect-resistance heat in ovens and fur- naces has many applications, from drying to melting. Induction heat- ing is used to heat metals for melting, forging, brazing, and hard- ening, as well as in many other less frequent applications. Dielectric and microwave heating is used for drying many materials from wood to foods, for processing plastic materials, and for an increasingly large application of microwaves in residential and commercial food heating. Table 9-39 presents the major advantages and disadvantages of electric heating. It should be emphasized that one of the major advantages often listed for electric heating is high efficiency. This is usually very true for electrical efficiency, that is, the percentage of electrical energy converted to usable heat. There is therefore less wasted heat in the user’s plant. However, the generation of electric- ity from fossil fuel is only about 30 percent efficient; therefore, over- all efficiencies of electric heat vary from I5 percent in a dielectric- heating application to 30 percent in a direct-resistance-heating application.
Direct-Resistance Heating Resistance losses (PA) in conductors are in general undesirable, but they can be desirable when the con- ductor is the load to be heated. This method is used in the iron and steel industry to preheat metal rods and billets prior to rolling or forging and for annealing similar shapes. Billets to be heated effi- ciently should have a length much greater than the diameter; oth- erwise, relative heat losses to the contacts will be large. For low-resis- tance metals such as copper, the L/D ratio should be greater than about 10. For relatively high resistance metals such as steel, the ratio can be lower. Cross sections of the rod should also be uniform for uniform heating. Energy consumption for heating to forging tem- peratures is approximately 300 kWh/ton. Comparable induction heating systems seldom realim better than 350 to 450 kWh/ton. Resistance heating systems also cost about 75 percent of the cost of an induction heating system.
The power supply for direct-resistance heating can be either three- phase or single-phase. It consists essentially of stepdown trans- formers and contactors with power-factor-correction capacitors often included. The whole system must also be strong to withstand the forces between high-current-carrying conductors, as currents of the order of ld A are not uncommon in the load circuit.
Contacts through which the current is transferred give rise to major design problems. Large areas of contact, with consequently low resistance, are good heat sinks and produce cold ends. Small con- tact areas with little heat withdrawal have high resistance and cause power losses and local overheating. Contacts also often must support the load. Careful design with some compromises is therefore called
TABLE 9-39 Comparison of glactrk-Heating Mothodr
Resistance heating Induction Dielectric
Direct Indirect heating heating
Clean:-no pollutants X Easilv controlled: accuratelv controlled X Efficient: leu h&t to sur&dings Lower capital investment Lower maintenance Electricity readily available Performing task impossible with fossil fuel Electricity generated by coal or nuclear reaction Heating electrical nonconductors Heat generated internally High electrical efficiency possible No direct contact
Disadvantages High cost of energy Uniformity of hept sometimes difficult Only limited energy sometimes available Low conversion efficiency from fossil fuel Hiah cart of conversion from mesent eauirxnent
X X X X
X X X X X X X
X X X
X X X
X X X
X X X X X X
X X X X X X X X X X
for. Multiple-end contacts have been used with both peripheral and end contact.
Direct-resistance heating of liquids such as molten glass or molten salts is also used. Glass above llOO°C is molten and has a resistivity sufficiently low for direct heating; current is passed between elec- trodes immersed in the melt. The electrodes must withstand both the high temperatures and the movement of the melt. Molybdenum or tin oxide electrodes are normally used Salt baths used for metal treatment have similar electrode problems. Graphite or corrosion- resistant steel is normally used. Generation of steam by passing cur- rent directly through water is also now common practice.
The preceding discussion assumed 60-Hz resistance heating. High- frequency resistance heating is also commonly used. This method takes advantage of both the “skin effect,” or shallow penetration of high-frequency current, and the “proximity effect,” in which the current follows the path of lowest reactance rather than that of low- est resistance. Such large applications as tube-seam welding and such small applications as selective area-surface hardening are uses of high-frequency resistance heating.
Indirect-Resistance Heating Indirect-resistance heating in- cludes surface resistance heaters, immersion heaters, uninsulated heating elements in furnaces and ovens, and infrared heaters. Factors affecting selection include the temperature coefficient of resistance, creep resistance, atmosphere of use, thermal-shock resistance, and need for high resistivity.
Industrial heating elements, for use in air, fall into four groups: nickel-base and iron-base, for metallic elements; and silicon carbide and molybdenum disilicide for nonmetallic elements.
The most widely used nickel-base heating elements consist of 80 percent nickel and 20 percent chromium and are generally recom- mended for a maximum element operatmg temperature of 1ZOO’G.
They form a coating of chromium oxide which protects the material from excessive oxidation. However, they are not recommended for use in furnace atmospheres which contain traces of sulfur because of a low-temperature reaction with nickel.
ELECTRIC HEATING 9-55
For slightly higher element temperatures, up to 1375°C (WOOoF), iron-base alloys are widely used. These consist mainly of iron, chro- mium, and aluminum. In air, the aluminum oxidizes and forms a tightly adhering film of alumina which protects the material from oxidation. These alloys, as well as the nickel-chromium series, can readily be shaped into coils or sinuated strips.
For element temperatures above 1375V (2500°F) nonmetallic materials are needed. Silicon carbide elements can be used up to 16OO’X (2912OF). These elements are made in the form of a straight rod, sometimes with a spiral cut. One of the characteristics of silicon carbide is that resistance increases with time (this property is called aging), making it necessary to use electrical equipment which pro- vides for numerous voltage settings.
Another type of nonmetallic element, molybdenum disilicide, pro vides element temperatures up to 17OOOC (3092OF) while avoiding the aging problems of silicon carbide. These elements are made of a cermet containing 90 percent M&s and 10 percent ceramic addi- tives. They soften at high temperatures and in general are made in U-shaped sections. Table 9-40 summarizes the data on the types pre- viously discussed and also includes others such as graphite and plat- inum. Platinum has the disadvantage of high cost but the advantage of low corrosion. Graphite has the advantage of highest temperature use, high blackbody radiation coefficient, high resistance, high ther- mal-shock resistance, and low thermal expansion but the disadvan- tage of oxidation at low temperatures in an oxidizing atmosphere.
Resistance heaters are used for many relatively low temperature applications in which direct contact is made with the insulated ele- ment. These include applications from plastic-sealing heat sources to melting soft metals. As flexible insulated heaters, these heaters are also used for heating pipes in many industrial areas.
Elecrrlc furnaces and uveus a&c u& fur a r*i& ralr~~ uI pfiv cesses ranging from annealing, hardening, and forging metals to drying many materials in hot air. Ovens are usually defined as oper- ating up to about 450% (842OF) and furnaces as operating above this temperature. The dominant mode of heat transfer in ovens and
TABLE 940 Materials Uwd for RristancaHwting Elomonts
Mean temperature Maximum operating coefficient of tenmerature in drv Resistivitv at resistivitv over
Material air, “C ’ 2ooc, ll:m operating range Principal applications
Vacuum furnaces; reducing atmospheres Small glass-melting furnaces; forehearths Furnace heating elements; oxidizing and reducing atmospheres
Lanthanum chromite 1800 2 x 10-s
‘Approximate compoJitions only. t Not in air.
9-56 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
furnaces is radiation, although convection and conduction from air heated by the elements make a large contribution, depending upon the furnace type.
A large number of different construction methods are used for fur- naces. The most common include box furnaces with heating elements in the furnace cavity, forced-convection furnaces with heaters exter- nal to the cavity, hot-retort furnaces with the load sealed from the outside air and the heating elements, low-thermal-mass furnaces using fiber insulation rather than ceramic refractories, cold-retort furnaces with heat reflectors protecting the heat from the walls, and muffle furnaces with the heater outside a refractory tube. The choice for various applications includes such factors as the atmosphere desired, start-up and shutdown times, and the maintenance schec- uling required.
Furnace insulation consists mostly of oxides of aluminum, silicon, magnesium, and zirconium. Furnaces for heat treatment generally use high-grade aluminosilicate bricks for lining. Filer insulation of aluminates and silicates has a very low thermal conductivity and low heat capacity and is used for low-thermal-inertia designs suitable for batch processing. High-purity alumina and zirconia fibers have recently pushed the upper temperature limits of fibers to about 1700°C (3092OF). However, if temperatures above this level must be used, carbon powder, either in submicrometer size or pelletized, is the only satisfactory insulation. Its thermal conductivity is somewhat higher than that of fibrous insulation, but it is still a satisfactory insulator.
Infrared (IR) heating, or radiant heating, is advantageous because the work need not be contacted by the heating elements or by cir- culating air. The heaters must have a line of sight to the surface to be heated. Although generation of heat and delivery to the load are more efhcient than in other furnace or oven methods, infrared heat- ing can be less efficient overall because the portion of the energy used depends upon the absorptivity of the load. The radiation is controlled by re5ectors, which also contribute to the efficiency. The intensity distribution of an IR source varies with the temperature, and more power 1s radlared at shorter wavelengths as the temperature increases. IR sources of relatively low temperature are normally used for heating nonmetallic materials which absorb at long wavelengths. High-temperature sources with most output at shorter wavelengths are required to heat metals which absorb them better.
The advantages of IR heating are: 1. It can heat up portions of a process or product. 2. Less floor space is needed than for other ovens. 3. Production can be increased easily by adding heating units to
current units to heat more at local areas or more overall. 4. High-flow exhaust systems can be replaced with lower-flow
systems because air is not heated excessively. 5. Product temperatures up to 65O“C (1202OF) are practical.
Early IR systems were simply on-off controlled heaters. Current sil- icon-controlled-rectifier (SCR) controls make possible closed-loop automatic temperature control.
There are three major types of IR heaters: wide-beam, with about a 100’ reflector and low power density; multibeam, with several reflector angles available to establish desired power densities and coverage; and heavy-duty, which have power ratings up to 20 or 30 kW, have a medium beamwidth of about 60°, and are selected for mechanical ruggedness. Three types of heating elements are available:
1. Quartz lamps, which are the most radiation-efficient, and are tungsten elements in a clear evacuated quartz enclosure
2. Quartz tubes, which have a nickel-chrome element in a quartz enclosure and are used for wide-beam heaters and a broad selection of power levels
3. Metal rods, which consist of a nickel-chrome element sur- rounded by magnesium oxide insulation with an outside metal sheath and are used in heavy-duty heaters
Induction Heating Induction heating provides a means for the precise heating of electrically conducting objects. In some cases, it is the only practical method of supplying heat to the work material. It is clean, fast, and repeatable and lends itself to automatic cycling. No contact is-required between the workload and the heat source, and
TABLE 9-41 Maior Applications of Induction Heating
Application Approximate frequency range, Hz
Melting 60-10 k Surface hardening 10 k-10 M Brazing and soldering 10 k-10 M Forging 60-3k Tube wlding 10-500 k Annealing ~10 k Strip heating 10-500 k Semiconductor-zone refining 50-500 k
heat may be restricted to localized areas or to a surface zone of the load.
Induction heating occurs when electrically conductive materials, such as metal workpieces, are immersed in an alternating magnetic field. This field is usually produced by an electrical coil energized by a suitable source of alternating-current electric energy. The ac mag- netic field induces voltages in the conductive material, and these voltages cause circulating currents (eddy currents). The magnitude of the induced currents is determined by the effective magnitude of the induced voltage and the im of induced current generates
pdance of the workpiece. The flow I R losses and heat in the workpiece.
Additional heat is produced in magnetic workpieces as the result of hysteresis losses; this heat is usually small, but in some cases involving strong magnetic fields the heat resulting from hysteresis losses can become significant. Table 9-41 lists major applications of induction heating.
Induction heating is efficient and practical if certain basic rela- tionships dealing with the frequency of the magnetic field and the properties of the workpiece are satisfied. Although the relationships are not sharply critical, they must be satisfied to the extent that a suitable degree of skin effect is produced in the workpiece. Skin Jf,=,+ in the phmnmmnn h, whit-h th P r,rrrentc flming in the urn&-
piece tend to be most intense at the surface, while currents at the center are near zero. As a consequence of this distribution the cur- rents produce a greater rate of heating near the surface. Skin effect is present in every successful induction-heating application.
Consideration of the operating frequency should be the first step in the design of a successful induction-heating installation. To achieve efficient induction heating, there must be a proper ratio of workpiece diameter (or thickness) to reference depth. For a given workpiece diameter, the thinner the current-carrying layers, the greater the rate of heat generation in the surface, other factors remaining constant. If minor effects are ignored, the effective depth of the current-carrying layer depends on the frequency of the ac magnetic field and on the electrical resistivity and magnetic perme- ability of the workpiece. Frequency is the only one of these factors that can be readily manipulated.
The current density in a workpiece decreases exponentially from
FIG. 942 Reference depth for common materials as a fun&on of frequency.
0.01 1 10 100 1000
Percent of critIcal frequency
FIG. 943 Relationship between relative efficiency and critical frequency.
the surface. The rate of decrease can be compared from one appli- cation to another by means of reference depth. Reference depth, which has actual physical significance in certain special cases, is defined by
d=5m\/;;7;f (9-41)
where d is the reference depth, cm; p is the resistivity of the work, il.m; p is the relative magnetic permeability of the work, dimen- sionless; and f is the frequency of the alternating magnetic field of the work coil, Hz. Figure 9-62 shows reference depth versus fre- quency for various common metals. It can be shown that if the ratio of workpiece diameter to reference depth drops below about 4: 1, the efficiency of heating decreases. The critical frequency is defined as the frequency at which the workpiece-to-reference-depth ratio is 4.5:1 for round bars; if heating sheet from both sides, the ratio is 2.25: 1. Figure 9-63 shows the efficiency of heating as a function of this critical frequency.
For a shallow depth in a large workpiece, a high frequency is selected. There is no concern about critical frequency, since the diameter will be many times the skin depth. However, for the fastest through-heating, a frequency close to the critical frequency must be chosen, and the calculations of reference depth and efficiency become more important.
The rate of heat generation for induction heating is proportional to the coil ampere-turns squared. The electrical resistivity of the work governs the rate of heat generation in it by I’R. In a magnetic load, there are also developed hysteresis losses which are negligible compared with the 1% losses unless exceptionally strong fields are present. In heating a nonmagnetic load that has a low resistivity, large currents must be used in the work coil to achieve high heating rates. Coil losses therefore tend to be high and efficiency low when heating a low-resistivity workpiece. The efficiencies for heating var- ious types of loads with various types of coils are given in Table 9- 42.
Induction furnaces operating at frequencies from 60 to 1000 Hz are useful for obtaining temperatures up to 3000°C (5432OF). In one
TABLE 943 Induction Power Sources
ELECTRIC HEATING 9-57
TABLE 942 Average Coupling Efficiencies for Induction Heating
of Ckm-Coupled Loads
I
Helical-around work Helical-internal One turn-around work One turn-internal. Hairpin Pancake
Copper
0.30 0.20 0.25 0.15 0.25 0.20
type of furnace, the currents are induced directly in the charge; in others, the currents are induced in a conductive case containing the charge, and the heat is radiated inward to the furnace charge. Since the coil currents may be as high as 15,000 A, the coil conductors are usually hollow to permit water circulation for cooling. Compared with resistance heating, the power factor of induction heating is rel- atively poor at 60 Hz because of the reactance effects. This tends to lower the overall plant power factor, which may incur power pen- alties from the utility company. Power-factor-correction capacitors are normally used.
Power sources to the induction coil fall into four categories, and the type to be used usually depends upon the frequency range desired. The four types are supply frequency (60 Hz), solid-state- converted systems, motor-alternator systems, and vacuum-tube sys- tems. Table 9-43 summarizes the four systems with their features and frequency limits. Some supply-frequency magnetic multipliers are still used, but they are generally being replaced by solid-state sys- tems. Since about I965 solid-state systems have also been increasingly replacing motor-alternator systems in the middle-frequency range. The main advantages of solid-state systems are possibly higher effi- ciency and no warm-up time, and the main advantages of motor- alternator systems are fixed frequency and easier maintenance. The features may be advantages or disadvantages depending upon appli- cations. Vacuum-tube radio-frequency power supplies have long been used for shallow, rapid surface-heating applications. The upper frequency limit of solid-state systems is about 50 kHz, and these sys- tems cannot currently compete with vacuum-tube supplies above that frequency.
Dielectric Heating Dielectric heating is the term applied to the generation of heat in nonconducting materials by their losses when subject to an alternating electric field of high frequency. The fre- quencies necessary range from 1 to 200 MHz. Heating of noncon- ductors by this method is extremely rapid. This form of heating is applied by placing the nonconducting load between two electrodes, across which the high-frequency voltage is applied. This arrange- ment in effect constitutes an electric capacitor, with the load acting as the dielectric. Although ideally a capacitor has no losses, practical losses do occur, and sufficient heat is generated at high frequencies to make this a practical form of heat source.
The frequency used in dielectric heating is a function of the power
Source Frequency range Power range Effeciency,
% Features
Line-frequency
Motor-alternator
Solid-state
Vacuum-tube
M) Hz
500 Hz-10 kHz
500 Hz-50 kHz
50 kHz-10 MHz
100 kW-100 MW
10 kw-1 MW
10 kW-1 mW
l-500 kW
9&95
75-85
75-95
65-75
High efficiency; low cost; no complex equipment; deep current penetration
LOW sensitivity to ambient heat; low sensitivity to line surge; fixed frequency; low-cost maintenance; spares not needed
No standby current; high efficiency; no moving parts; protection needed outdoors; no warm-up time; impedance matching the changing loads
9-58 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
desired and the size of the work material. Practical values of voltages applied to the electrodes are 2000 to 5000 V/in of thickness of the work material. The source of power is exclusively by electronic (vac- uum-tube) oscillators which are capable of generating the very high frequencies desirable. Units with up to 500-kW output are in com- mercial use. Some of the more common uses of dielectric heating are wood drying, curing, and gluing; preheating of plastics; processing of rubber and synthetic materials; food processing; and drying and heat treatment of textiles.
The basic requirement for dielectric heating is the establishment of a high-frequency alternating electric field within the material or load to be heated. Once the electric field has been established, the second requirement involves dielectric-loss properties of the material to be heated. The dielectric loss of a given material occurs as a result of electrical polarisation effects in the material itself. There are at least four recognized types of such polarization: two which occur as a result of the field itself, or induced polarisation; and two which are inherent and are determined by the arrangement of the component particles of the material itself. These loss mechanisms are (1) elec- tronic polarization, (2) atomic polarisation, (3) dipole orientation, and (4) space-charge polarization. The latter two are most prominent in dielectric heating.
The volume rate of power input P, to a dielectric material can be expressed in watts per cubic inch as
P, = 1.41E2fe, tan 6 X lo-‘* (Q-42)
where E = electric field, V/in; f = frequency of electric field, Hz; L, = relative dielectric constant of the work; and tan 6 = dielectric loss tangent of the work. or the complement of the power factor single, that is:, the or& bctwocn the roltago and currr;nt in ~lr~ dielectric material. The product of t, and tan 8, called the loss factor, is often listed in tables of dielectric properties of materials for various frequencies (see Table 9-44).
Microwave Heating Microwave heating is simply dielectric heating at still higher frequencies, done in a cavity where the wave- length is of the order of the cavity size rather than large compared with the applicator, as in low-frequency heating. The two predomi- nant frequencies used in microwave heating are 915 and 2450 MHz. Since microwave heating is 10 to 100 times higher in frequency than the usual dielectric heating, from Eq. (Q-42) it can be seen that a lower voltage is needed if the loss factor is constant. However, the loss factor is generally greater at microwave frequencies. Also at microwave frequencies there is a definite skin depth in high-loss- factor materials analogous to the skin depth in induction heating. The skin depth is
I
0s
(Q-43)
where d is the penetration depth, in; o is the velocity of light, in/s; and f, e,, and tan 6 are as in Eq. (9-42). Skin depth is important in heating foods, for example, in which it is quite large in frozen foods with a small loss factor but small in room-temperature foods such as unfrozen meat.
Microwave heating is rapidly becoming the key to new techniques and processes. This form of heating has begun to proliferate as its
TABLE 9-44 Typical Dielectric loss Factors for Various Materials
Material Loss factors
Spruce wood, dry 6% moisture 10% moisture.
Paper. Text&e Hard rubber Porcelain Cellulose acetate
cost has come within range of an increasing number of users. The range of applicability of microwave heating is determined by eco- nomic factors, which include but may not be limited to price per pound of the finished product, existence of special features such as instantaneous heat programming or differential heating, savings in storage space or tooling which result from a significant reduction in heat-cycle time, reduction in raw-material costs for equal-quality final product, reduction of in-process shrinkage and/or loss, and superiority of the final product.
The conversion of utility-power-line power to microwave power into the product is estimated at 50 percent. Basic microwave-power sources cost about $25OO/kW, the microwave energy applicator about $5OO/kW, and tube replacement costs about $0.06/h (all 1980). Microwave-power sources for industrial use are available in l-, 5-, 20-, and 30-kW modules, which can be ganged to meet spe- cific process-power requirements.
Two distinct areas for the use of microwave energy in chemical processing are developing. One area utilizes the direct absorption of microwaves to effect rapid and efficient heating of dielectric mate- rials without heating the surroundings or associated low-dielectric- loss materials. This form of radiant energy is being studied or used for large-scale food processing (cooking, sterilization, freeze drying, etc.) and for such industrial processes and products as ceramics, chemicals, coatings, electronics, forest products, graphic arts. paper, pharmaceuticals, plastics, rubber, and textiles. Typical functions per- formed are bonding, curing, deinfestation, drying, foaming, fusing, heat treating, polymerisation, and sealing. Utilization in many cases goes beyond just a replacement for or complement to a heating cycle. This is, in part, due to the ability of microwaves to penetrate dielec- 11ic urac~-rialr nud LU lx abwrbcd tbrougtwut the entt~ exposed WA- ume and thereby to generate heat uniformly. It is also, in part, due to the selectivity inherent in microwave heating. For example, in drying moist materials, the microwave power is absorbed in the wet- test regions and essentially passes through the dried regions. This selectivity of heating offers a means for self-limiting the energy taken up by heterogeneous materials, and overheating is unlikely. With these combined effects, microwave heating often can do a heating job more quickly, in less space, without undue superficial heating, without thermal lag, and, therefore, with rapid control.
The other area of microwave energy under development involves chemical synthesis by means of microwave-coupled plasmas. As an accurately controlled, monochromatic source of electromagnetic radiation, microwaves supply the alternating electric field necessary for the continuous ionization of a gaseous substance passed through this field. The ionized gas, or plasma, offers several routes to chemical synthesis: the plasma contains ionized species and electrons; it can supply radicals and/or excited atomic and molecular species; and it can be used as a precise ultraviolet-light source for photochemical reactions.
Electric-Arc (Plasma) Heating Electric heating by means of plasma formation has rather significant usage. The plasma is formed from gases or vapors of reactive or diluent constituents of a process stream and electrons in voltage gradient. A plasma is a partially ion- ized gas containing molecules, atoms, ions, electrons, and free radi- cals, each moving with a certain velocity. The plasma is in thermal equilibrium when the average energy of each species is the same and the laws of thermodynamics apply. Thermal equilibrium is approached at pressures of 101.325 kPa (1 atm) and at power levels sufficiently high to maintain an electron concentration of >lO” cm-s. Plasmas having these properties are known as arc discharges. Devices that supply the electric power to form and employ arc dis- charges are the electric-arc furnace, the induction plasma, and the plasma jet.
The principle of electric-arc heating is that when an electric cir- cuit is interrupted (by an air gap), current will continue to flow if the current is high enough to vaporize some of the conductor and thus fill the gap with a conducting vapor path. The electric-arc furnace is capable of operating at temperatures up to the order of 3500°C (6332°F). At such temperatures, the electric furnace has no eco nomic competitors. The main uses are in the purification of ores, changing an undesirable crystalline structure of an ore, and synthesis
FIRED PROCESS EQUIPMENT 9-59
of compounds not available in the natural state by fusing different raw materials. The arc furnace is therefore used extensively in the metallurgical, abrasive, refractory, and electrochemical industries.
The arc is established by momentarily bringing together two elec- trodes, or one electrode and the charge (which frequently acts as a second electrode), and then separating them. The vapor produced on separation provides the conducting path. The preferable method of operation is with a short arc which gives rise to high currents. Volt- ages up to 250 V are normally used in arc furnaces in conjunction with tap-changing transformers to obtain the most suitable voltage. Typical electrode materials are graphite and carbon. Graphite is more expensive and purer and has greater strength and higher CUT- rent-carrying capacity than carbon. Severity of operation and purity requirements dictate the type of electrode to be used. Carbon arcs are the most intense source of heat, with a temperature of about 5500% (9932’F). Electrodes are consumed in the heating process by oxidation and by contact with the furnace charge. In the direct- arc furnace, the voltage is applied between two or more electrodes located above the charge, which in most cases is a nonconductor of electricity at room temperatures but becomes a conductor at higher temperatures. To fuse the charge, layers of coke are placed on the surface between electrodes. When the electrodes are lowered into the coke bed, a current flows, generating heat, which in turn melts the furnace charge near it. The charge then becomes conductive, and current will flow from electrode to electrode through the molten bath. Heat is generated by radiation from the electric arc between electrodes and bath and through the resistance-heating effect in the bath.
Arc furnaces may be single-phase or three-phase. For balanced electrical loads on the power supplies three-phase is desirable. How- ever. cingbphscp flwnawc pmprly connwtwl tn different ringlo.
phase power can also maintain an overall balanced system. Furnaces with capacities of 250 to 10,000 kVA are in commercial use. Sizes in the range of 1000 to 2000 kVA are most common. Since the position of the electrode is critical, automatic regulators are used to control the position of the electrodes to maintain constant current, voltage, or power--whichever is desired.
The plasma jet can be operated with direct or alternating current. The water-cooled metal electrodes are nonconsumable, and the gap between the electrodes is made conductive by passing an easily ion- ized, unreactive gas such as argon or helium between them. The gas velocity attains supersonic levels. For the purpose of heating, reactive gases can be added either to the inert gas stream at low levels before passing through the electrode region or, at high levels, to the heated inert gas outside the electrode region. Pure reactive gases cannot be used because of the reactivity of the electrodes with them. Similar restrictions exist when a particulate solid is a reactant. Because of the high velocities encountered in the plasma jet device, contact time in the maximum heat-flux region is extremely short. Temperatures in excess of 8COO°C (14,432’F) exist in gas issuing from such a device.
The limitations set by the electrodes in the electric-arc and plasma-jet devices are eliminated in the induction plasma generat- ing device. Power from a radio-frequency source operating up to 20 MHz is transferred to the thermally ionized gas by inductively cou- pling to the partially conductive gas. The energy transfer occurs by inducing high-frequency current in a very thin annulus on the out- side of the load, much as current would be induced in a thin-walled steel tube located in the same position within the multiturn coil.
At a frequency of 4 MHz and power levels up to 10 kW only mon- atomic gases can be used to initiate the arc. Reactive diatomic gases can be metered into an argon plasma and heated. The plasma is extinguished at a critical ratio fixed by the type of gas added and the reactor geometry. At higher frequencies and output power levels, larger amounts of a diatomic gas can be metered into the argon plasma without the gas being extinguished.
Since no electrodes are exposed to the plasma region, more types of reactions at elevated temperatures can be undertaken than in the plasma jet or the electric (carbon)-arc devices. The induction plasma device is useful as a clean heat source for crystal growth or spheroid- ization and for high-temperature chemical processes which are endo-
thermic overall. For exothermic reactions, rapid quenching of the heated products is required.
Laser Heating Laser heating is accomplished by the absorption of light energy on a material surface, except in the case of semitrans- parent materials, which can absorb light energy beneath the surface. The absorption of light energy by a material surface may vary from 1 to 99 percent, depending on the specific material and the condition of mechanical and/or chemical surface preparation. The uniqueness of laser heating results from the high level of energy shaping which may be accomplished optically with the monochromatic, coherent laser light energy. Energy densities delivered to a material surface can easily exceed 10s W/cm* in a small focal spot or may be reduced to much lower levels for broad-area coverage, depending on the heating requirement.
While the cutting and drilling of metals, plastics, ceramics, and organics are the most widely practiced applications for laser heating, the greatest amount of laser energy is consumed in the transforma- tion hardening (heat treating) of steels and cast irons to improve the wear performance of specific locations on mechanical components. Laser welding of automotive-transmission components is also begin- ning to consume larger amounts of laser energy.
Although hundreds of different laser types have been successfully operated, continuous-wave CO* lasers provide by far the greatest amount of industrial laser energy. These machine tools provide out- put powers of 50 to 15,OCKl W in the far-infrared (10.6~Km) wave- length and may be operated continuously or in pulsed fashion. The lasing medium is a mixture of low-pressure CO*, NP, He, and some- times 02 or CO which is excited by an electric-glow discharge. Laser light energy is extracted from the excited medium by means of an optical “resonator” composed of at least two mirror surfaces, one of whia-h ic partially ,rzanrpwen+ 14 pmviAer the n,,tp,,t helm Flew.
trical conversion efficiencies for CO1 lasers range from 5 to 14 per- cent, and their operating costs per watt of delivered power are the lowest for any industrially significant laser-heating equipment.
FIRED PROCESS EQUIPMENT
Twenty-four major energy-intensive industries depend on direct- fired or indirect-fired equipment for drying, heating, calcining, melt- ing, and chemical processing. Some of these industries used coal and producer gas at first and switched to natural gas or oil when these fuels were less expensive than coal. There is a strong movement now to return to coal and coal-derived gases and to adapt to coal processes that conventionally used other fuels. This subsection will deal with both direct- and indirect-fired equipment, with the greatest emphasis on indirect firing for chemical-process industries.
Steam generation for process heat and electric power production is the largest user of indirect firing and is handled separately under “Steam Generators.”
Direct-fired combustion equipment is that in which the flame and/or products of combustion are used to achieve the desired result by direct contact with another material. Common examples are rotary kilns, open-hearth furnaces, and submerged-combustion evaporators.
Indirect-fired combustion equipment is that in which the flame and products of combustion are separated from any contact with the
TABLE 9-45 Industrial Amhations of Direct and Indirect Firina
Industrv Direct Indirect
Fmd Lumber Paper Petroleum Rubber and elastics Glass Cement Lime Ore beneficiation Coke Iron and steel
x
x x x x
x x x x
x x
9-60 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TABLE 946 Average Energy Consumption Rote in Process Industries
SOURCE: M E. Fejer et al., Assessment Applkafirm for Direct Coal Com- bwtkm, Institute of Gas Technology, Chicago, National Science Foundaliorr Cont. NSF-024, October 1976.
‘To convert l@ British thermal units per ton to megajoules per kilogram, multiply by 1.16.
principal material in the process by metallic or refractory walls. Examples are steam boilers, vaporizers, heat exchangers, and melting pots. Table 9-45 shows the 11 industrial applications of both these types of fired process equipment.
Direct-Fired Equipment Table 9-46 gwes the average energy consumption in seven major industries that use direct firing. Table 9- 47 shows the kinds of equipment used in the direct-fired cement and lime industries and the respective energy consumption per ton of product. Details of the equipment are described in a report entitled “Assessment Application for Direct Coal Combustion,” issued in 1977 by the National Science Foundation. Section 20 of this edition describes and illustrates rotary dryers, rotary kilns, and hearth and multiple-hearth furnaces.
Indirect-Fired Equipment The following discussion is based largely on articles by Herbert L. Berman [“Fired Heaters I, II, III, and IV,” Chem. Eng. (June 19, July 31, Aug. 14, and Sept. 11, 1978)]. Process-industry requirements for fired heaters are divided into a half-dozen general service categories.
Column Reboilera The charge stock taken from a distillation column is a recirculating liquid that is partially vaporized in the fired heater. The mixed vapor-liquid stream reenters the column, where the vapor condenses and releases the heat of vaporization. Depend- ing on the particular application, reboiler heater outlet temperatures generally faj] in the range of 204 to 288OC (400 to 550°F).
Fractionating-Column Feed Preheater8 The charge stock (usually all liquid, although some feeds may contain a nominal amount of vapor at the inlet) is sent to the fired heater following upstream preheating in unfired equipment.
A typical example of this service is the feed heater for an atmo- spheric distillation column in the crude-oil unit of a petroleum refin-
TABLE 9-47 Energy Consumption of Various Cement- and Lime- Manufacturing Roceues
PrOCESS lo6 Btu/ton’
Cement
Wet
Long kilnf 5.9 Calcinator and short kiln 4.7
Semiwet: preheater and short kiln 36
Dry Long kiln 4.7 Suspension preheater and short kiln 3.2
Semidry grate preheater and short kiln 3.4 Lime
Rotary long kiln+ 7-8 Rotary short kilnt 5-6 Vertical kiln 4.5-5.0 Rotary-hearth kiln 4.5-5.0
‘To convert lo6 British thermal units per ton to megajoules per kilogram, multiply by 1.16.
tMost common in the United States.
ery. Here, crude oil entering the fired heater as a 371°C (700°F) liquid might exit near 232OC (450’F) with about 60 percent of the charge stock vaporized.
Reactor-Feed Preheater5 Fired heaters in this application raise the charge-stock temperature to a level necessary for controlling a chemical reaction taking place in an adjoining reactor vessel. The nature of the charge stock and the heater operating temperatures and pressures can vary considerably, depending on the process. The following examples illustrate the diversity of the applications per- formed by reactor-feed preheaters.
. Single-phase-single-component heating such as steam super- heating in the reaction sections of styrene-manufacturing pro- cesses. In this service, the fluid temperature across the fired heater increases from an inlet temperature of about 371°C (700°F) to an exit temperature of about 816’C (15OO’F).
. Single-phase-multicomponent heating, such as the heating of mixtures of oaportted hydrocarbons and recycle hydrogen gas prior to catalytic re-forming in a refinery. In this service, the charge stock enters the fired heater at about 427OC (8CWF) and exits at approximately 538’C (1OOOOF). In re-farmers, the fluid pressure may range from about 1.723 X 10s Pa (250 psig) to 4.137 X 10s Pa (600 psig). Severe restrictions on fluid pressure drop are normally associated with this service.
* Mixed-phase-multicomponent heating, such as the heating of mixtures of liquid hydrocarbons and recycle hydrogen gas for reac- tion in a refinery hydrocracker. Fluid temperatures typically run from 371°C (700°F) at the inlet to 454’C (850’F) at the outlet. Operating pressures may reach 20.685 X 10s Pa (3000 psig), depend- ing on the process.
Heat Supplied to Heat-Transfer Media Many plants furnish heat to individual users via an intermediate heat-transfer medium. A fired heater is generally employed to elevate the temperature of the recirculating medium, which is typically a heating oil: Dow- therm, Therminol, molten salt, etc. Fluids flowing through the fired heater in these systems almost always remain in the liquid phase from inlet to outlet.
Heat Supplied to Viscous Fluids Often heavy oil must be pumped from one location to another for processing. At low temper- atures, at which the oil may have so high a viscosity as to render pumping infeasible, a fired heater is employed to warm the oil to a temperature that will facilitate pumping.
Fired Reactors In this category are heaters in which a chemical reaction occurs within the tube coil. As a class, these units represent the fired-heater industry’s most sophisticated technology. The follow- ing two applications typify the majority of installations.
- Steam hydrocarbon-re-former heaters, in which the tubes of the combustion chamber function indivtdually as vertical reaction vessels filled with nickel-bearing catalyst. In reformers that yield hydrogen, fluid outlet temperatures range from 788 to 899OC (1450 to 1650OF).
- Pyrolysis heaters, used to produce olejins from gaseous jeed- stocks such as ethane and propane and from liquid feedstocks such as naphtha and gas oil. In cracking heaters, in which chemical reactions occur in the coil, the tubes and burners are arranged so as to assure pinpoint firing control. Fluid outlet temperatures in heaters designed for liquid feedstocks are in the 816 to 899OC (1500 to 1650°F) range.
The principal classification of fired heaters relates to the orienta- tion of the heating coil in the radiant section, i.e., whether the tubes are vertical or horizontal. Vertical arrangements are shown in Fig. 9. 64; horizontal arrangements, in Fig. 9-65. Salient features of each follow.
Vertical-Cylindrical; All Radiant Here the tube coil is placed vertically along the walls of the combustion chamber. Firing is also vertical, from the tloor of the heater.
Heaters of this type represent a low-cost, low-efficiency design that requires a minimum of plot area. Typical duties are 528 X 10s J/h to 21 GJ/h (0.5 to 20 million Btu/h).
Vertical-Cylindrical; Helical Coil In these units, the coil is arranged helically along the walls of the combustion chamber, and firing is vertical from the floor. Although these heaters are grouped
Extended -surface
area
Radtant coil ._
Burner5 ,’
/’ 1 I
‘Termjnal mamfolds
-Radtant coil--
FtG. 9-64 Vertical-tube-fired heaters can be identified by the vertical arrangement of the radiant-section coil. (a) Vertical- cylindrical; all radiant. (b) Vertical-cylindrical; helical coil. (c) Vertical-cylindrical, with cross-flow-convection section. (d) Vertical-cylindrical, with integral-convection section. (e) Arbor or wicket type cf) Vertical-tube, single-row, double-fired [From Chem. Eng., 100-101 (June 19, 1978).]
P-61
u lcll
117[
Fi - 000 0000 000
0000
a00 l-II oao a00
a00 _------Convect~on coil -----_______
000
.-__
JPaa@ll
i/ 0 0 0
oooo OOQQ
0000 n y 0 Q 0
0 3 0 0 3 0 0 0 0 0
0 a 0 0 1 0
0 0 3 0
lu II----l
Convection coil-.,
-*. 000 n 000 000 600
800 i==l ,Convectlon coil
,A 000 a@00 @@@ 0000 000 8 8
0 ___--0
0 0 n 0 0 8 8 0 0 0
0800333~~~~3~ 0 0 0
.‘Q
I
‘=To stack -
Radiant coil-
fdl
FW 9-U Six basic designs used in horizontal-tube-fired heaters. Radiant-se&on coil is horizontal. (a) &bin. (b) Two-~11 box. (c) Cabin with dividing bridgewall. (d) End-fired box. (e) End-B& bo x. with side-mounted convection section. cf) Horizontal-tube, single-row, double-fired [From Chem. Eng., NL?-IO.~ (tune 19, IN%).]
9-62
with others having vertical-tube designs, their in-tube characteristics resemble those of horizontal-tube heaters.
This design also represents low cost and low efficiency and requires a minimum of plot area. Heating duties are the same as for the pre- ceding heater.
Vertical-Cylindrical, with Cross-Flow Convection These heaters, also fired vertically from the Boor, feature both radiant and convection sections. The radiant-section tube coil is disposed in a ver- tical arrangement along the walls of the combustion chamber. The convection-section tube coil is arranged as a horizontal bank of tubes positioned above the combustion chamber.
This configuration provides an economical, high-efficiency design that requires a minimum of plot area. The majority of new vertical- tube fired-heater installations fall into this category. Typical duty range is 10.6 to 212 GJ/h (10 to 200 million Btu/h).
Vertical-Cylindrical, with Integral Conoection Although this design is rarely chosen for new installations, the vast number of exist- ing units of this type warrants its mention in any review of fired heaters.
As with the preceding types, this design is vertically fired from the floor, with its tube coil installed in a vertical arrangement along the walls. The distinguishing feature of this type is the use of added sur- face area on the upper reaches of each tube to promote convection heating. This surface area extends into the annular space formed between the convection coil and a central baffle sleeve. Medium effi- ciency can be achieved with a minimum of plot area. Typical duty for this design is 10.6 to 106 GJ/h (10 to 100 million Btu/h).
Arbor or Wicket This is a specialty design in which the radiant heating surface is provided by U tubes connecting the inlet and out- let terminal manifolds. This type is especially suited for heating large Bows of gas under conditions of low pressure drop. Typical applica- tions are found in petroleum refining, in which this design is often employed in the catalytic-re-former charge heater, and in various reheat services. Firing modes are usually either vertical from the floor or horizontal between the riser portions of the U tubes.
This design type can be expanded to accommodate several arbor coils within one structure. Each coil can be separated by dividing walls so that individual firing control can be attained. In addition, a cross-tlow convection section is normally installed to provide supple- mentary heating capacity for chores such as steam generation. Typ ical duties for each arbor coil of this design are about 53 to 106 CJ/ h (50 to 100 million Btu/h).
Vertical-Tube, Double-Fired In these units, vertical radiant tubes are arranged in a single row in each combustion cell (there are often two cells) and are fired from both sides of the row. Such an arrangement yields a highly uniform distribution of heat-transfer rates (heat tlux) about the tube circumference.
Another variation of these heaters uses multilevel sidewall firing, which gives maximum control of the heat-flux profile along the length of the tubes. Multilevel-sidewall-firing units are often employed in fired-reactor services and in critical reactor-feed heat- ing services. In addition to the twin-cell furnaces already mentioned, single-cell models are available for smaller duties. As a group, these represent the most expensive fired-heater configuration. The typical duty range for each cell runs from about 21 to 133 GJ/h (20 to 125 million Btu/h).
Horizontal-Tube Cabin The radiant-section tube coils of these heaters are arranged horizontally so as to line the sidewalls of the combustion chamber and the sloping roof, or “hip.” The convection- section tube coil is positioned as a horizontal bank of tubes above the combustion chamber. Normally the tubes are fired vertically from the floor, but they can also be fired horizontally by sidewall-mounted burners located below the tube coil. This economical, high-efficiency design currently represents the majority of new horizontal-tube fired-heater installations. Duties run from 10.6 to 106 GJ/h (10 to 100 million Btu/h).
Two-Cell Horizontal-Tube Box Here the radiant-section tube coil is deployed in a horizontal arrangement along the sidewalls and roof of the two combustion chambers. Vertically fired from the Bow, this is again an economical, high-efficiency design. Typical duties range from 106 to 266 GJ/h (100 to 250 million Btu/h).
FIRED PROCESS EQUIPMENT 9-63
Horizontal-Tube Cabin with Dioiding Btidgewall Again the radiant-section tube coil is arranged horizontally along the sidewalls of the combustion chamber and along the hip. The convection-sec- tion tube coil takes the form of a horizontal bank of tubes positioned above the combustion chamber. A dividing bridgewall between the cells allows for individual firing control over each cell in the com- bustion chamber. A typical duty range for this design is 21 to 105 GJ/h (20 to 100 million Btu/h).
End-Fired Horizontal-Tube Box The radiant-section tube coil is disposed in a horizontal arrangement along the sidewalls and roof of the combustion chamber. The convection-section tube coil is arranged as a horizontal bank of tubes positioned above the combus- tion chamber. These furnaces are horizontally fired by burners mounted in the end walls. A typical duty range for this design is 5.3 to 53 GJ/h (5 to 50 million Btu/h).
End-Fired Horizontal-Tube Box, with Side-Mounted Conoec- tion Section Here the radiant-section tube coil is disposed in a hor- izontal arrangement along the sidewalls and roof of the combustion chamber. The convection-section coil is arranged as a horizontal bank of tubes positioned alongside the chamber. The unit is horizon- tally fired from burners mounted on the end wall.
These furnaces are found in many older installations and occasion- ally in new facilities that burn particularly poor grades of fuel oil containing a high ash concentration. This relatively expensive design provides duties ranging from 53 to 212 GJ/h (50 to 200 million Btu/
h). Horizontal-Tube, Double-Fired Horizontal radiant tubes are
arranged in a single row and are fired from both sides to achieve a uniform distribution of heat-transfer rates around the tube circum- ference. Such heaters are normally fired vertically from the Boor. They are often selected for critical reactor-feed heating services. For increased capacity, the concept can be expanded to provide for a dual combustion chamber. A typical duty range for each cell of this design is about 21 to 53 GJ/h (20 to 50 million Btu/h).
Fuel-Saving Methods for Existing Heaters Because of increased fuel costs, industries that operate process heaters must give serious consideration to improving fuel-burning efficiency. They can now justify increased costs for more efficient major equipment and control instrumentation. In today’s environment, industrial-boiler and process-heater efficiency not only is measured in British thermal units but must also reflect the much greater dollar cost of those units. Figure 9-66 illustrates one of the two basic methods of improving design for fuel conservation:
1. Optfmite air for conbu.stion. Reduction of total air to the left of the zone of maximum combustion efficiency will result in increasing unburned-fuel loss. Heat loss is rapid when all the fuel is not burned. To the right of the zone of maximum combustion effi- ciency, the losses rise with increasing excess air.
Save
Total air percent
FIG. 9-66 One of two basic methods of improving design for fuel conserva- tion. Air is optimized for combustion. Heat is trapped out of flue gas (with air heaters or ecanomizers). [From Combustion, NJ-16 (November 1978).]
9-64 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Dew points for sulfur-
330 - free flue gas
0” % Excess Dew point
$ 310 - air OF ‘C
0.01 0.05 0.1 0.5 1 .o
Sulfur in Fuel Oil, Percent/Wt.
5.0 10.0
zlt3~-67 Maximum flue-gas dew point versus percent of sulfur in typical oil
An additional factor is that when excess air is increased, flue-gas temperature rises, and this compounds with excess-air loss Excess-air loss rises at a slower rate than does the loss from unburned combus- tibles by a factor of about 6 (316% stack temperature); therefore, it is important to keep the flue gas out of the combustibles’ range. There is a aone, then, of maximum combustion efficiency where the sum of the losses is at a minimum. The extent of overlap between combustible gas and excess oxygen depends on the particulars of a given installation, the type of burners, and the fuel fired.
2. Recowr heat in flue gas. If the &e-gas temperature is high, this thermal-energy loss can be reduced by installing heat exchangers that absorb energy from the stack gases. Air heaters and feed pre- heaters are well-known examples of such equipment.
Corrosion problems in air heaters are associated with high flue-gas dew points because of SOs formation from sulfur in the fuel. The curves in Figs. 9-67 and 9-68 can be used to determine safe upper limits for dew points in fired heaters burning liquid or gaseous fuels.
STEAM GENERATORS
Steam generators are designed to produce steam for process require- ments, for process needs with electric power generation, and solely for electric power generation. In each case, the prime incentive is to design the most efficient and reliable boiler for the least cost. Many factors influence the design and selection of the type of steam gen- erator, and some of these will be discussed later in connection with industrial and utility boilers,
Dew points for sulfur-
360 - free flue gas
0” % Excess Dew Point
0.01 0.05 0.1 0.6 1.0 5.0 10.0
H2S in Gas Fuel, PercedVol.
EJU6 Maximum flue-gas dew point versus percent of HpS in typical gas
In the industrial market, boilers have been designed to burn a wide range of fuels and operate at pressures up to 12.4 MPa (1803 Ibf/in*) and steaming rates extending to 455,006 kg/h (l,OOO,C@O lb/h). High-capacity shop-assembled boilers range in capacity from 4500 kg/h (lo,@30 lb/h) to about 250,ooO kg/h (550,000 lb/h). These units are designed for operation at pressures up to 11.1 MPa (1650 psig) and 763 K (950°F). Figure 9-69 shows a gaseous-liquid fuel-fired unit. While most shop-assembled boilers are gas- or oil-fired, designs are available to burn pulverized coal. The significant increase in the cost of fuels and the greater reliance on coal have provided the incentive toward large-capacity field-erected boilers operating at higher pressures with superheat and possibly reheat. A field-erected coal-fired industrial boiler is shown in Fig. Q-70.
Boilers designed for service in electric power utility systems oper- ate at both subcritical-pressure [pressures below 221.1 bar (3206 lbf/ in*)] and supercritical-pressure steam conditions. Subcritical-pressure boilers range in design pressures up to about 18.6 MPa (2700 Ibf/in*) and in steaming capacities up to about 2946 Mg/h (6,500,OOO lb/h). A subcritical-pressure boiler is shown in Fig. 9-71. Supercritical-pres- sure boilers have been designed to operate at pressures up to 344.5 bar (5006 psig). In practice, the 241.2-bar (3500-psig) cycle has been firmly established in the utility industry, and boilers with steaming capacities up to 4219 Mg/h (9,300,ooO lb/h) and superheat and reheat temperatures of 614 K (1065’F) are in service.
Some Fundamentals of Boiler Design Boiler design involves the interaction of many variables: water-steam circulation, fuel char- acteristics, firing systems and heat input, and heat transfer. The fur- nace enclosure is one of the most critical components of a steam gen- erator and must be conservatively designed to assure high boiler availability. The furnace configuration and its size are determined by combustion requirements, fuel characteristics, emission standards for particulate matter, and the need to provide a uniform gas flow and temperature entering the convection heat-absorbing surfaces to minimize ash deposits and excessive superheater metal temperatures, Discussion of some of these factors follows.
Circdution and Heat Tramjer Circulation, as applied to a steam generator, is the movement of water or steam or a mixture of both through the heated tubes. The circulation objective is to absorb heat from the tube metal at a rate that assures sufficient cooling of the furnace-wall tubes during all operating conditions, with an ade- quate margin of reserve for transient upsets. Adequate circulation prevents excessive metal temperatures or temperature differentials that would cause failures due to overstressing, overheating, or corrosion.
The heat transfer from the tubes to the fluid depends primarily on turbulence and heat flux. Turbulence is a function of mass velocity of the fluid and tube roughness Turbulence has been achieved by designing for high mass velocities, which ensure that nucleate boiling takes place at the inside surface of the tube. If sufficient turbulence
FtG. 9-69 Shop-assembled boiler.
Ro. 9-70 Cad-fired industrial boiler.
f
FIG. 9-71 Subcritical-pressure utility boiler.
9-66
STEAM GENERATORS 9-67
Steam water mixture
Heat
*
Film boiling
Transition boiling
_-_-__
Nucleate boiling
me---
357
water FIG. V-72 Effect of departure from nucleate boiling (DNB) on tube-metal temperature
is not provided, departure from nucleate boiling (DNB) occurs. DNB is the production of a film of steam on the tube surface that impedes the Bow of heat to cool the tubes. This phenomenon is illustrated in Fig. 9-72.
Satisfactory performance is obtained with tubes having helical ribs on the inside surface, which generate a swirling flow. The resulting centrifugal action forces the water droplets toward the inner tube surface and prevents the formation of a steam film. The internally rifled tube maintains nucleate boiling at much higher steam qualities and with much lower mass velocities than those in smooth tubes. This improvement is shown in Fig. 9-73.
Circulation ratio, defined as the weight of circulating flow divided by the weight of steam generated, is an empirical criterion for eval-
454 Tube-metal temperature, oC
566
uating the performance of circulation systems. In modern practice, however, the most important criterion in drum boilers is the preven- tion of conditions that lead to DNB.
Utility Steam Generators
Steam-Generator Circulation System Circulation systems for utility application are generally classified as natural circulation and forced or pump-assisted circulation in drum-type boilers and as once- through 5ow in subcritical- and supercritical-pressure boilers. The circulation systems for natural- and pump-assisted circulation boilers are illustrated schematically in Fig. 9-74.
Natural circulation in a boiler circulation loop relies only on the
Rifled tube
Ho. 9-73 Maximum allowable percent of steam to avoid departure from nucleate boding (DNB).
9-48 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
difference between the mean density of the fluid (water) in the downcomers and the mean density of the tluid (steam-water mixture) in the heated furnace walls. The difference in these densities pro vides the drive that causes flow in the loop. The actual circulating head is the difference between the total gravity head in the down- cumer and the integrated gravity heads in the upcoming legs of the loop containing the heated tubes. The circulating head must balance the sum of the Bow losses due to friction, shock, and acceleration throughout the loop.
In a once-through system, the feedwater entering the unit contin- uously absorbs heat until it is completely converted to steam. The
cl W4
EASTERN BITUMINOUS
0 1.0BWm6D
MIDWESTERN BITUMINOUS
SUB-BITUMINOUS
1.07H L
total mass Bow through the waterwall tubes equals the feedwater flow and, during normal operation, the total steam Bow. The key fact of circulation at supercritical pressures (above 221.1 bar, or 3206 lbf/ in’) is the existence of a single-phase tluid at any temperature, and there is no need for a steam drum.
Fuel Characteristics Fuel characteristics have a major impact on the design and operation of a coal-fired boiler. Coals having a low volatile matter usually require higher ignition temperatures, and those with less than 12 to I4 percent volatile matter may require supplementary fuel to stabilize ignition. Generally, western United States coals are more reactive and, consequently, easier to ignite, but
1.16W~l.OBO 1.26Wx1.24D 1.29Wx1.26D
WILCOX SEAM VEGUA-JACKSON SEAM
TEXAS LIGNITE
NORTHERN PLAINS LIGNITE
Ro. 9-75 Effect of coal rank on furnace sizing.
STEAM GENERATORS 9-69
because of high moisture content they require higher air tempera- tures to the mills for drying the coal to attain proper pulverization. Extremely high-ash-content coal could create problems in ignition and stabilisation. The ash constituents and the quantity of ash will have a decided influence on sizing the furnace. Accordingly, a thor- ough review of coal characteristics is needed to establish the effect on the design and operation of a boiler.
In designing and sizing furnaces, particular attention is required for the following fuel-ash properties:
1. Ash fusion temperatures in terms of their absolute values and the spread between initial deformation temperature and 5uid temperature
2. Ratio of basic to acidic ash constituents 3. Iron-to-calcium ratio 4. Ash content, kg/l,O%,OOO kJ (lb/million Btu) 5. Ash friability These characteristics translate into the furnaces shown in Fig. 9-
75 for five United States coals. Note the progressive increase in fur- nace size in terms of plan area, volume, and burning zone as lower- grade fuels are fired to develop equivalent steam-5ow capacity. There are wide variations in coal properties within the coal ranks as well as several subclassifications (e.g., subbituminous A, B, C) of these fuels. These variations require a different size of furnace for each classification.
Coal properties in5uence pulverizer capacity, the sizing of the air heater, and other heat-recovery sections of a steam generator. Fur- nace size and heat-release rates are designed to control slagging char- acteristics. Consequently, heat-release rates, in terms of net heat in ut to plan area, range from 4,420,OOO W/m2 [1.4 million Btu/(h’
fib;] f or severely slagging coals to 6620,000 W/m8 [2,100,000 Btu/ (h.ft*)] for low-slagging fuels.
Fin’ng-gysfem Heat Znput Heat input is a critical design crite- rion in establishing the combustion of fuel with regard to minimizing the formation of the oxides of nitrogen (NO,) in the combustion pro- cess. To accomplish these functions, the designer considers the fol- lowing design parameters:
* Design and size of burners and their arrangement in the furnace . Clearances from burners to water-cooled surfaces * Furnace release rate, (kg.cal)/m* (Btu/ft*) effective projected
radiant surface or EPRS * Furnace-gas residence time for combustion and NO, emissions . Furnace exit-gas temperatures, K (OF) . Combustion rate, kJ/m8 (Btu/fta) . Burner-zone release rate, W/m8 [Btu/(h.fta)] Firing systems can be classified into two groups: . Wall firing, in which individual flames are formed by burners in
the front, rear, and/or side walls of the furnace . Tangential firing, in which fuel and air are introduced into the
furnace from delivery nozzles located in the corners of the unit A major difference between the systems is that in wall firing there
is little interaction among the Barnes from individual burners; in tan- gential firing, reactants from all coal nozzles interact, forming a cyclonic name mass and making the furnace a single “burner.”
The furnace of large coal-fired steam generators absorbs about one-half of the heat released, so that the gas temperature leaving the furnace is about 1376 K (2000°F).
Superheater8 and Reheaters The superheater raises the tem- perature of the steam generated by the boiler to some point above saturation. The thermodynamic advantage of superheating steam is shown in Fig. 9-76, which compares the available head above a given exhaust condition with the total heat in the steam. Another important point is to minimize moisture in the last stages of a turbine to avoid blade erosion. With continued increase of evaporation temperatures and pressures, a point is reached at which the available superheat temperatures are insufficient to prevent excessive moisture from forming in the low-pressure turbine stages. This condition is resolved by removing the vapor for reheat at constant pressure in the boiler and returning it to the turbine for continued expansion to condenser pressure. The thermodynamic cycle using this modification of the Bankine cycle is called the reheat cycle. Figure 9-77 illustrates the surface arrangements in a high-pressure boiler.
Economizers Economizers improve boiler efficiency by extract- ing heat from the discharged 5ue gases and transferring it to feed- water, which enters the steam generator at a temperature apprecia- bly lower than the saturation-steam temperature.
Industrial Boilers A common definition of an industrial boiler is a stationary water-tube boiler in which some of the steam is gener- ated in a convective tube bank. The percentage of total heat absorp tion in the boiler bank varies considerably with boiler steam pressure and temperature and feedwater temperature. For a typical coal-5red boiler producing 90,720 kg/h (200,000 lb/h):
The thicker plate for operation at higher pressures increases the cost of boiler drums. As a result, it is normally not economical to use a boiler bank for heat absorption at pressures above 109 kg/cm* (1550 psig).
Industrial boilers are used over a wide range of applications, rang- ing from large power-generating units, for which emphasis is placed on maximum efficiency and sophisticated control systems, to small low-pressure units for space or process heating, for which the prin- cipal aims are simplicity and low first cost.
While an industrial boiler’s primary function is usually to provide
energy in the form of steam, there are a number of applications in which steam generation is incidental to a chemical process, e.g., a chemical recovery unit in the paper industry, a carbon monoxide boiler in an oil refinery, or a gas-cooling waste-heat boiler in an open- hearth furnace. Within a given industrial plant, it is not unusual for industrial boilers to serve a multiplicity of functions. For example, in a paper-pulp mill the chemical-recovery boiler is used to convert black liquor into useful chemicals and to generate process steam. At the same plant a bark-burning unit recovers heat from otherwise wasted material and also generates power. Industrial boilers burn oil, gas, coal, and a wide range of product and/or waste fuels as shown in Table 9-43.
Current statistics show that pulverized-coal firing is the choice for larger boilers, above 113,398 kg/h (WO,@Xl lb/h). For boilers in the medium-size range, 45,359 to 113,398 kg/h (100,090 to 250,009 lb/ h), stoker-fired boilers dominate, although the percentage of pulver- ized-coal-fired boilers in this range is increasing. The higher thermal efhciency of a pulverized-coal-fired boiler makes it attractive toward the upper limit of the medium-size range.
A major factor to consider when comparing a stoker-fired boiler with a pulverized-coal-fired boiler is the reduction in efficiency due to carbon loss. A properly designed pulverized-coal-fired boiler can maintain an efficiency loss due to unburned carbon of less than 0.4 percent. A continuous-ash-discharge spreader-stoker-fired unit will typically have a carbon loss of 4 to 8 percent, depending on the amount of reinjection. Dumpgrate, underfeed, or overfeed stokers
TABLE 9-48 Solid-Waste Fuels Burned in industrial Boilers
‘To convert kilojoules per kilogram to British thermal units per pound, mul- tiply by 4.299 X 10-l
produce an even higher carbon loss. The lower carbon loss produced with the pulverized-coal unit results from increased combustion effi- ciency obtained from the finer coal particles that enter the furnace (normally 70 to 80 percent will pass through a ZOO-mesh screen). In contrast, the coal particles that enter the furnace with a spreader stoker are much coarser, with a I9-mm top size and not more than 50 percent passing through a KS-mm screen.
The coal itself also affects the total fuel-cost difference between these firing methods. For efficient operation of a spreader-stoker- fired boiler, the coal must have the proper mixture of coarse and fine particles. Normally, double-screened coal is purchased to obtain the proper mixture. One cannot depend on run-of-the-mine coal to have the optimum balance of coarse and fine material. The fine coal par- ticles are burned in suspension above the grate, while the larger par- ticles burn on the grate surface. If the amount of fine particles is too great, excessive suspension burning will occur with the following pos- sible results:
. Higher stack particulate-matter loading
. Furnace pulsations
. Possible heat damage to the distributors
. Higher carbon loss and smoke If the amount of coarse coal is too great, there will be insufficient suspension burning with these possible results:
. Loss of ilame stability
. Higher carbon loss and smoke If it is decided not to use double-screened coal, there will be a loss in efficiency as the coal sizing diverges from the optimum. The question of whether the reduced efficiency obtained with unsized coal is offset by the higher cost for double-screened coal cannot be answered on a general basis. The answer depends on such factors as degree of coal- sizing variation, quality of operators, boiler or stoker size, and coal classification.
A pulverized-coal-fired boiler requires only that the coal entering a mill be IX-in top size. Coal of any size can be purchased and crushed at the plant site if the proper size is not available at the mine.
In addition to designing for a range of coals, liquid, gaseous, or other solid fuels may be considered. Because pulverized coal is sus- pension-fired, as are conventional liquid and gaseous fuels, the fur- nace is properly proportioned for this function. Oil or gas is required for unit warm-up; therefore, the required piping, combustion con- trols, and fuel-firing equipment are in place. These fuels can be fired to carry load with little or no design or equipment modifications. Firing a liquid fuel derived from coal or a coal-oil slurry would also be possible because the furnace has been designed to cool the gases below the ash-softening temperature before these gases enter the closely spaced generating bank section.
Well-prepared solid wastes may also be burned in suspension. Up to 20 percent of the total heat input may be added. Bark, bagasse,
STEAM GENERATORS 9-7 1
and refuse have all been successfully suspension-fired in a pulver- ized-coal-fired boiler. These wastes are normally blown into the fur- nace pneumatically through ports located above the burners.
For a stoker-fired boiler, firing liquid or gaseous fuels is more dif- ficult The firing equipment must be placed high above the stoker to protect it from the radiant heat produced by the auxiliary burners. The placement of firing equipment high in the furnace reduces the effective furnace volume. For long-term operation, it may be nec- essary to cover the stoker with refractory. For short-term operation, considerable quantities of air are required to cool the stoker, result- ing in large quantities of excess air, which is inefficient. While firing liquid or gaseous fuels in a stoker-fired boiler is more difficult, the stoker is ideally suited for firing other unsized solid fuels. Bark, bagasse, or refuse can normally be fired on a stoker to supplement the coal with a minimum amount of additional equipment. Also, these waste fuels can comprise a higher percentage of the total heat input in a stoker-fired boiler than in a pulverized-coal-fired boiler.
Design Criteria Industrial-boiler designs are tailored to the fuels and firing systems involved. Some of the more important design criteria include:
* Furnace heat-release rates, both W/m3 and W/m2 of effective projected radiant surface [Btu/(h.fts) and Btu/(h.fts)]
. Heat release on grates * Flue-gas velocities through tube banks . Tube spacings Table 9-49 gives typical values or ranges of these criteria for gas,
oil, and coal. The furnace release rates are important and establish maximum local absorption rates within safe limits. They have a bear- ing on completeness of combustion and therefore on efficiency and particulate emissions. Limiting heat release on grates (in stoker fir- ing) will minimize carbon loss, control smoke, and avoid excessive By ash.
Limits on flue-gas velocities for gas- or oil-fired industrial boilers are usually determined by the need to limit draft loss. For coal firing, design gas velocities are established to minimize fouling and plug- ging of tube banks in high-temperature zones and erosion in low- temperature zones.
Convection tube spacing is important when the fuel is residual oil or coal, especially coals with low ash-fusion or high ash-fouling ten- dencies. The amount of the ash and, even more important, the char- acteristics of the ash must be specified for design. The recommended
TABLE 949 Tv~ical Dostan Parameters for Industrial Boilers
minimum tube spacing for industrial solid-fuel-fired boilers is shown in Table 9-50.
Natural-circulation and convection boiler banks are the basic design features on which a line of standard industrial boilers has been developed to accommodate the diverse steam, water, and fuel requirements of the industrial market.
Figure 9-78 shows the amount of energy available for power by using a fire-tube boiler, an industrial boiler, and subcritical- and supercritical-pressure boilers. Condensing losses decrease substan- tially, and regeneration of air and feedwater becomes increasingly important in the most advanced central-station boilers.
The boiler designer must proporton heat-absorbing and heat- recovery surfaces in a way to make the best use of heat released by the fuel. Waterwalls, superheaters, and reheaters are exposed to con- vection and radiant heat, whereas convection heat transfer predom- inates in air heaters and economizers. The relative amounts of these surfaces vary with the size and operating conditions of the boiler.
Factors Influencing Performance Some of the dominant factors influencing performance are fouling, slagging, moisture in the coal, grindability of the coal, and heating value of the coal.
The volatile constituents in coal ash (i.e., NarSO, or CaSOI. NasSO,) cause fouling and can be used as a fouling index of a given coal. Two factors that affect fouling are deposit hardness and the rate of deposition. Deposit hardness is affected by chemical composition, temperature, and, to some extent, time. The rate of deposition depends on the volatile constituents of coal and the amount of ash in the coal. In general, fouling is related to the sodium and potassium compounds in the ash, and it becomes severe as the level increases above 4 to 5 percent NaaO and KaO for high-calcium, low-iron ash coals. Slag deposits are caused primarily by the physical transport of molten or partially fused ash particles entrained by the gas stream. When the particles strike the wall or tube surfaces, they become
lb)
ICI Id1
FIG. 9-78 Sankey diagrams for various types of boilers. (a) Fire-tube boiler. (b) Industrial boiler. (c) Subcritical-pressure boiler. (d) Supercritical-pressure boiler.
9-72 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
chilled and solidify. The strength of their attachment is influenced by the temperature and physical contour of the surface, direction, force of impact, and melting characteristics of the slag. Coals with low ash-fusion temperatures have a high potential for slagging [below 2200°F (1477 K)]. Normally, slagging is confined to the radiant surfaces, but it also occurs in the convection superheater if the gas temperature exceeds good design practice. Slagging charac- teristics affect the furnace design, requiring a significant increase in furnace volume to reduce the potential for deposit formation.
High moisture in coal influences furnace performance. Excess sur- face moisture compounds the difficulties of handling coal at the exit of the bunker into the inlet of the feeder and at the feeder outlet into the pulveriser. Wet coal within the pulveriser causes it to ball up and inhibit grinding. Such problems are typical with coal having a high inherent moisture in the fuel, up to 30 percent. In these cases, providing sufficient high-temperature air will obviate pulverisation problems.
The high moisture in the fuel lowers the flame temperature, reducing local furnace absorption and ignition stability, especially during start-up. High moisture also reduces boiler efficiency, owing to heat losses up the stack.
The grindability index is a measure of the relative eax of pulver- ising coal. The fineness required for both good ignition and complete combustion of coal depends on a number of factors, including vola- tile matter, agglomerating properties, and particle reactivity. In terms of rank, low-volatile bituminous coals must be pulverized to a
higher degree of fineness than subbituminous coals and lignites to ensure carbon burnout. The grindability of coals varies over a wide range. Pulveriser output related to pulveriser base capacities for var- ious grindability indices is shown in Fig. 9-79. Grindability can be a significant factor in limiting rated boiler output when coal having a looererrindabihty than that for which the pulveriser was sized is
The heating value of coal has a significant intluence on boiler per- formance. The greatest potential for variations in the pulveriser out- put rate is the result of fuel heating-value variations. The lower heat- ing value of hgnites and subbituminous coals creates a potential limitation in boiler output because it takes more coal for a given heat input. Heating values range from 12,000 Btu/lb (27,912 kJ/kg) for an eastern bituminous coal to 6800 Btu/lb (15,817 kJ/kg) for north- ern plains lignite. The range of firing rates of various United States coals to yield comparable heat inputs for a given unit is shown in Table 9-51.
Stacks and Chimneys
Theoretical Draft The theoretical draft is that which is pro duced by the manometric difference in static head of equal columns of atmospheric air and combustion gases. The theoretical draft of a smokestack or a chimney can be calculated readily from the formula
ZA 14.1 (SOT/hr) I I
I / I I I I 10 15 20
Pulverizer capacity kg/s
(55 grind - 70% through 200 mesh)
24 (KIT/~)
Ro. 9-79 Pulveriser capacity: grindability index. To convert kilograms per second to tons per hour, multiply by 3.543.
STEAM GENERATORS 9-73
TABLE 9-51 Ranae of United States Ceal Promertiar’
Eastern Midwestern Subbituminous Texas Northern bituminous bituminous C lienite lignite
HHV, kJ/kg 27,900 Moisture, 95 6 Moisture, kg HgO/CJ
where Ap, = theoretical stack draft, in water; L = stack height above furnace, ft; P = barometric pressure, inHg; T = ambient
where Apf = stack flow loss, in water; u = stack exit velocity, ft/s;
temperature, OR; and T1 = average stack temperature, OR. Figure g = dimensional constant, 32.17; f = friction factor from Fig. 9-
9-800 may be used to estimate the exit-gas temperature required to 80b; L = stack height above furnace, ft; D = stack diameter, ft; and
obtain the average stack temperature for masonry or steel stacks. ps = average density of gases in the stack, Ib/fts. To apply Fig. 9- 80b the Reynolds number may be approximated by the equation
Actual Draft To obtain the actual draft for a chimney or stack, the losses that occur with Bow must be deducted from the theoretical draft. These losses include both friction and exit velocity. They may be evaluated by the following equation:
Nae = 24,000 X W
D(T, + 715) (9-46)
where T, = average stack temperature, OF W = gas Bow, lb/h
FIG.
(9-45) / The actual draft may be obtained by subtracting the frictional losses from the theoretical draft. This quantity is known as the nat-
FtG. 9-800 Exit-gas temperatures from stacks
5 lo5 2 5 lo6 2 5 10’
Reynolds number, NR~
9-Mb Friction factors for stacks. (Bobcock G Wilcox Co.)
80,000w-400p-655’F.-1337h Ow Reduclnq valve
(and desuperheater) -------_---___-_)-
I t-----+=+---1
FIG. 9-80~ Steam-plant-cycle diagram showing by-product generation of electric power and process steam. Heat supplied in steam = 97 kJ/h (92 X lo6 Btu/h). Heat supplied in fuel = 121 kJ/h (115 X 106 Btu/h). Net plant electric send-out = 4700 kW.
ural draft of the chimney, since it is produced without mechanical means. When it is insufficient to overcome the tlow resistance of the system, fans must be added. If the fans supply air at pressures above atmospheric to the burners and combustion space, they are called forceddraft fans. If the fans handle the products of combustion, they usually operate at pressures below atmospheric and are called induced-draft fans.
Special Problem Frequently stacks are required to handle gases of a highly corrosive nature. Even the gases of conventional fuels may contain sufficient amounts of contaminants such as sulfur trioxide to attack steel and concrete rapidly. Efforts should be made to maintain temperatures above the dew point or to reduce partial
9-74 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
pressures by dilution when condensable acid gases occur. When cor- rosive conditions warrant the extra expense, chimneys and stacks are frequently lined with glass, acid-resistant brick, or acid-resisting cement. Steel stacks may be purchased lined with bonded glass for erection as a unit, or they may be lined in place with brick after erection. Masonry stacks are erected in place of either brick or rein- forced-concrete design. Either steel or masonry stacks may be lined after erection with special coatings applied by hand or by pressure spraying (guniting). It is advisable to inspect stacks for internal cor- rosion at periodic intervals. Water washing after cooling is advisable to expose the surface for inspection if the stack is heavily coated with soot.
HEAT TRANSPORT
GENERALREFWIMCES: The Dowtherm Handtook, Dow Chemical Company, Midland, Mich., 1960. G&ringer, Handbook of Heat Transfer Media, Rein- hold. New York. 1962. “High Temperature Heating Media,” Chem. Eng. Prog., 59(S), 33-53 (1963) Keenan and Keyes, Thmodynamtc Properttes of Steam, Wiley, New York, 1956. Kent. Mechanical Engineers’ Hnndhk, vol. 2: Pourer, 12th ed., Wiley, New York, 1950. Kern, Process Heat Transfer, t&Craw-Hill, New York, 1950. McAdams. Heat Transmissia, 3d ed., McGraw-Hill, New York, 1954. Marks, Mechonlcal Engineers’ Handbwk, 7th ed, McGraw-Hill, New York, 1950.
Liquids and vapors used to transport heat and give it up to process require a unique combination of properties. High boiling points and low pressures reduce hazards and permit economical designs, while high heat capacity improves the ability to carry heat and spread it evenly through the process system. The tluids must also be commer- cially available and economical to use.
Solid materials are also used for heat transport. These materials have never reached the importance of liquids and vapors, primarily because of the difficulty of transporting the solid particles through small pipes and bent tubes. Pebbles, sand, and iron balls can be heated to higher temperatures than liquids and have found applica- tion in air and gas heaters for high-temperature equipment.
The commonly used heat-transport fluids are listed in Table 9-52, along with their useful temperature ranges and corresponding pres- sure ranges.
Historically, the open flame is the oldest source of heat known to man. Basic simplicity and low equipment cost have enabled it to sur- vIvc In many lodusrrlal processes. The open ftame as a heat source for industrial-product heating has several limitations, however. These include low fuel efficiency, minimum control over uniformity of heat absorption, and correspondingly poor control over local tem- peratures in the product material. The burners, fuel supply, and con- trols must be at the operating point, making the units unwieldy and not suitable to locations of advantage to the manufacturing opera-
TAME 9-52 Commonly Used Heat-Transport Fluids*
~
Chlorinated biphenyls’ NaK
Flue gas or air
:~z& : Mercury O-180
I 30-2000 O-100
‘See Table 9-54 for more detailed data. To convert pounds per square inch gauge to kilopascals, multiply by 0.15; “C = (OF - 32) x %.
tions. As a result of these limitations, fluids adaptable to much closer control long ago supplanted tlame for process work.
STEAM SYSTEMS
System Characteristics To utilize the energy that is stored as chemical energy in fuels, the chemical energy must be converted to a more usable form, generally either electrical energy or mechanical energy, to drive machines, or thermal energy, as a source of process heat. Although some fuel energy is converted directly to mechanical energy (as in combustion engines) or to thermal energy (direct-pro- cess heating), the most popular systems involve the use of steam as an intermediate medium. Steam is the most widely used heat-trans- port fluid owing to its nontoxic nature, stability, low costs, and high heat capacity. It has limitations, too: its high vapor pressure and its low critical point.
Most commercial sytems start with energy in the form of chemical energy in fuel. Combustion of the fuel in the furnace converts the chemical energy to thermal energy in the form of high-temperature combustion products. In a boiler, heat is transferred from the corn- bustion products to water, thus producing steam. The steam may then be used for driving machinery (Including turbmes) or for heat- ing (process or space). The use of steam can be via three types of systems:
1. Steam-electric systems (in which nearly all the steam is used to drwc a turbine-generarorj
2. Cogeneration systems (in which steam is used both to drive a turbine-generator and for heating, usually in series)
3. Steam systems (in which steam is used as a heat-transfer medium for heating purposes only)
Steam-electric and steam systems are discussed in the following paragraphs. Cogeneration systems are dealt with in another part of this subsection.
Steam-Electric Systems Steam-electric systems utilize super- heated steam to drive turbine-generators to produce electrical energy. Unless special circumstances exist, economics are unfavora- ble for small- to moderate-size process plants to consider steam-elec- tric systems. The unfavorable economics include the high capital cost of the furnace-boiler system, the generally lower operating efficiency of small boiler systems, high operating and maintenance costs, and the cost of capital equipment for meeting air-pollution-emissions regulations for the combustion process.
Special circumstances that can justify the operation of small steam- electric systems include the availability of a low-cost fuel, such as a waste or by-product fuel. Industries can make use of such by-product fuels as bark, black liquor, bagasse, sawdust, blast-furnace gas and coke-oven gas, and fluid coke, either as main fuels or in combination with conventional fuels such as coal, oil, or gas.
Cogeneration systems greatly increase the opportunities for a pro- cess plant to generate electric power economically.
STEAM SYSTEMS 9-75
Steam Systems* Steam systems include those systems in which steam is generated and used for process and/or space heating and, less frequently, for the direct driving of machinery. Although indus- trial steam can be generated at high pressure (up to 12.4 MPa) and temperature, most industrial steam systems are limited to about 1.724-MPa (2.5~lbf/in’) steam pressure and 204OC (400°F) steam temperature. In an industrial steam system, the major component is the furnace-boiler unit; another major component is the condenser, if one is used.
Furnace-boiler units are constructed as integrated units; design varies with size and fuel. Small gas- and oil-fired boilers, with capac- ities up to 31.7-Mg (70,000-lb) steam per hour, are usually fire-tube boilers. Most solid-fuel-fired boilers and larger gas- and oil-fired boil- ers are water-tube design. Water-tube boilers for industrial steam generation are of drum-type design. Water-tube boilers may be shop-assembled packaged boilers or field-erected. Gas- and oil-fired boilers of capacities to 113.4.Mg (250,mlb) steam/h can be installed as package units (to 550,COO lb/h if shipment is possible). Coal-fired boilers with capacities above about 11.3-Mg (25,000-lb) steam per hour are partially or totally field-erected. Because of the high cost of field erection, it may be more economical to install sev- eral smaller boilers than one large boiler. Also, because the minimum firing rate of boilers is about one-third of the design firmg rate, the use of several smaller boilers provides a much higher turndown ratio.
A typical steam-plant cycle for generation of process steam and electric power is shown in Fig. 9-8Oc. This is the cycle of an indus- trial power plant that requires the delivery of 5000 kW of electric energy and 22.7 Mg/h (50,000 lb/h) of dry saturated process steam at 137.9 kPa absolute (20 psia). Because all power cannot here be generated as a by-product of the process steam flow, a condensing element is added to the turbine and operated at 2.54 cmHg (1 inHg) absolute pressure. The heat balance of Fig. 9-8Oc is for one set of load conditions. Careful analysis of load curves is necessary for the selection of the most economical cycle.
Most industrial steam systems utilize saturated steam; thus, super- heaters are rarely used. Also, when low steam temperatures are used, there is no need for an economizer or an air preheater. However, pulverized-coal firing requires air preheat to achieve ignition and combustion stability.
The cost of coal-fired boilers is about 4 times the cost of packaged gas- and oil-fired boilers. Modern industrial boilers operate at effi- ciencies of about 85 percent.
including a condenser in the steam system provides opportunities for reusing the clean steam condensate, as opposed to providing clean boiler water continuously. The choice of whether or not to include a condenser in the system will vary with plant design and size, water availability, and water quality. The cost of return-water piping and a condenser becomes less attractive for widely dispersed plant facil- ities and as steam use decreases. Conversely, high steam (and, there- fore, water) use and limited water availability may make a condenser attractive.
Factors that must be considered when selecting an industrial boiler include:
. Fuels, including projected costs and availability * Steam requirements: temperature, rate of delivery, and pressure * Load profile; turndown . Boiler feedwater: source and treatment * Space requirements, including fuel storage . Air pollution emissions and regulations . Energy to drive auxiliaries . Operating personnel required Water Constituents Water, as the working fluid of steam sys-
tems, is one of the most widely dispersed natural substances but is never found in a pure state, suitable for direct feed to a boiler. Water in its natural state is usually turbid with solid matter in fine suspen- sion. Even when clear, natural water contains solutions of salts and acids that will quickly damage steel or copper-bearing metals in
‘See “Steam Generators” for further details on equipment.
steam systems. Recycling steam condensate from process heating is desirable to take advantage of the relatively pure condensate. Because of atmospheric dissipation and contamination from process equipment, some raw makeup is constantly required.
Various constituents in waters may be classed in accordance with the troubles that may result from their presence:
1. Corrosive substances 2. Scale-forming substances 3. Foam-producing substances Corrosive substances are usually in the form of acid solutions or as
dissolved gases such as carbon dioxide, oxygen, hydrogen sulfide, or ammonia. Oxygen and carbon dioxide are dissolved in the feedwater by aeration and unavoidable contact with the atmosphere. Since the solubility of oxygen decreases with an increase in water temperature, the most common method of removal is the deaeration of water, in which the water is heated to the boiling point by direct contact with steam and the heated water is allowed to cascade over trays. The trays increase the exposed surface and permit easier dissipation of the oxygen. Deaeration is also effective in removing other dissolved gases, and all modern steam systems use any of several types of deaerators. In addition to deaeration, use is made of chemicals, such as sodium sulfite, which combines with oxygen and is introduced into the boiler with a chemical feed pump. At higher boiler pressures sodium sulfite is less desirable, because of an increase in the dissolved solids produced by the end-product sodium sulfate and a decompo- sition into sulfur dioxide and hydrogen sulfide which contribute to corrosion. Hydrazine removes dissolved oxygen without increasing dissolved solids at high pressures with the following reaction:
NIHd + 02 - 2H20 + N2
High residuals of hydrazine in the water must be avoided to prevent the decomposition-product ammonia from attacking copper-bearing alloys in the system.
Reused water that is high in acidity must be treated to maintain a proper alkaline environment in which the pH is between 10.5 and 11.0. Bicarbonate alkalinity in the boiler can hydrolyze under the action of heat, and liberate carbon dioxide, which will be carried along with the steam to form a corrosive carbonic acid product with the condensate in process heat exchangers or condensate piping. Present-day practice calls for water treatment to prevent corrosion in the recycling system by means of neutralizing or filming amines. Neutralizing amines combine with CO1 and neutralize its acidity. Filming amines do not combine chemically but act by forming an impervious, nonwettable film on metal surfaces which acts as a bar- rier between metal and condensate, preventing both oxygen and car- bon dioxide attack.
Steam systems in which the bulk of condensate is unrecoverable are more often subject to difficulties caused by scale-forming sub stances. The makeup water invariably has constituents which will be scale-forming when present in the water in concentrations in excess of their solubility. Some materials exhibit a decrease in volubility with an increase in temperature, and the scales commonly deposited in boilers belong to this class Chemical treatment in the preboiler system is successful in reducing most scale-forming substances to a soft sludge, which is removed before it can enter the boiler, while sludges formed by internal treatment may be collected in quiescent zones of the boiler and removed through blowdown pipes.
Water recovered from process heating causes foaming within the boiler from the presence of organic, inorganic, or insoluble materials, when they are present in sufficiently large quantities. Oil and the products of decomposition of sewage and humic matter are the chief causes of foaming, and these products should be strictly excluded from condensate returns. The foaming effect of these materials is especially true in the presence of high alkalinities, and the alkaline concentration of boiler water should be limited for this reason.
Table 9-53 summarizes recommended limits for impurities in water used in boilers. Continuous or intermittent blowdown of the boiler water to keep concentrations below recommended limits is the most effective way of preventing foaming. When the blowdown
9-76 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
TABLE 9-53 Recommended limits for Boiler-Wahr Constituents Parts per milhon
NOTE: To convert parts per million (by weight) to micrograms per liter, mul- tiply by l/198; to convert pounds per square inch to kilopaxaln. multiply by 6.695
results in large quantities of heat being lost to the system, much of this heat may be recovered by passing the blowdown through heat exchangers used to heat feedwater or air, which returns some of the heat to the unit.
THERMAL-LIQUID SYSTEMS
Liquids and Their Properties Thermal liquids used for process heating and cooling may be in the form of liquids, vapors, or a com- bination of both. In addition to steam, thermal liquids include hot water, mercury, NaK, diphenyldiphenyl oxide (Dowtherm A), o- dichlorobenzene (Dowtherm E), molten salt mixtures, mineral oils, arylaryloxysilane (Hydrotherm 750-200), tetraaryl silicate (Hydrotherm 700-160), and chlorinated biphenyls (Therminols). Physical properties of these materials are given in Table 9-54.
High-temperature hot water is a favorable system for process temperatures of 149 to 204% (300 to 400°F) but requires pump pressures greater than the saturation pressure of 17.5 kg/cm (250 Ibf/in*) to maintain the water in liquid form. Hot-water systems are stable, with simple equipment, and easy to control. Corrosion is at a minimum when air is excluded from the system. Deleterious solids in the water do not build up to high concentrations in the absence of evaporation, and scale formation and foaming are at a minimum.
Dowtherm A (Dow Chemical Company) presently dominates the 204 to 399’C (400 to 750’F) field of indirect process heating. This &id is an organic compound of high heat stability, a eutectic mix- ture containing 73.5 percent diphenyl oxide and 26.5 percent diphenyl by weight. At its freezing point of 12.2’C (54OF) Dow- therm A contracts slightly, thereby removing the possibility of dam- age to process equipment when shut down under cold-weather con- ditions. At room temperatures it is a clear, almost colorless liquid, which darkens rapidly in use without change in physical character- istics, and has a characteristic rose-geranium odor. It does not react chemically with metals commonly used in heat-transport systems and is not toxic to humans, presenting no appreciable hazard to health in heat-transfer use and requiring no special precautions.
Dowtherm A is quite stable at moderately high temperatures. Many vaporizers and accessories have operated for years at Dow- therm temperatures of 343OC (65OOF) with no decomposition. At higher temperatures decomposition may occur in two ways. Above about 399% (750“F) two molecules of diphenyl may react to yield one molecule of p-diphenylbenzene and one of benzene. The p- diphenylbenzene dissolves in Dowtherm A, but the benzene, being a noncondensing vapor in practical Dowtherm heating installations, escapes into vent pipes. There is a similar reaction in the case of diphenyl oxide.
The second form of decomposition is more troublesome When Dowtherm A is severely overheated, such as by tlame impingement on the tubes of a vaporizer or by forcing the heater beyond its rated capacity, complete decomposition into carbon and hydrogen may take place. The formulation of carbon occurs when inadequate cir- culation caused by the accumulation of materials holds the Dow- therm in a stagnated condition. The lighter fractions then distil1 off,
leaving behind the higher-boiling-point fractions, which carbonize. When this begins, the carbon forms a skin on the heating surface of the vaporizer, and this increases the thermal resistance so that decomposition is greatly accelerated. In this manner, a Dowtherm vaporizer may be filled completely with carbon in a few hours.
To prevent overheating and decomposition, Dowtherm vaporizers are of liquid-tube or fire-tube natural-circulation design or liquid- tube forced-circulation design. Small laboratory vaporizers are fre- quently heated by electricity. A natural-circulation vaporizer as in Fig. 9-81 is arranged with few bends or restrictions to allow fast recirculation of the Dowtherm liquid, and is designed with ample furnace capacity. Good flame-shape control prevents hot spots from forming along the vaporizer tubes.
Dowtherm E, a specially processed o-dichlorobenzene which boils at 177OC (SOOF) and has a freezing point below zero, is commonly used between 177 and 260% (350 and 5CU’F). No trace of decom- position of Dowtherm E has been noted in tests conducted at tem- peratures and heat loads considerably higher than those recom- mended for commercial installations. There is some evidence that aluminum can catalyze the decomposition of Dowtherm E to form hydrochloric acid. This acid is likely to corrode severely the polished surfaces of precision tools, machines, and sheet or formed metals. Aluminum should not be used with Dowtherm E.
Znorganic Salta Molten mixtures of inorganic salts, one of which is a eutedic consisting of 40 percent NaNOs, 7 percent NaNOs, and 53 percent KNOs, are widely used in salt baths and petroleum refin- ing when high temperatures are maintained and when the system is kept in continuous operation. A melting point of 14V’C (288’F) pre- cludes their use in low-temperature systems and requires that the circulating fluid be kept hot and molten throughout its Bow path. The salt mixture need not be pressurized higher than required to overcome the pressure drop of the system.
Inorganic-salt mixtures are nontoxic and chemically stable up to 427 to 454°C (800 to 850’F) in the absence of contaminants. Between 454 and 593% (850 and llW“F), which is the maximum operating temperature, the salt undergoes a slow thermal decompo- sition, which is largely a thermal breakdown of the nitrite to nitrate, alkali metal oxide, and nitrogen:
5NaNOp - 3NaNOs + Na20 f NI
This reaction is evidenced by the slow evolution of nitrogen gas, and it is accompanied by a gradual rise in the freezing point of the mix- ture [Alexander and Hindin, Ind. Eng. Chem., 39, 1044 (1947)].
The nitrite is also subject to slow oxidation by atmospheric oxygen above 454OC (85OOF) with formation of sodium nitrate. This reac- tion is eliminated by excluding air or blanketing the salt with an atmosphere of inert gas such as nitrogen.
Other reactions will gradually alter the composition of the salt: (1) absorption of carbon dioxide to form carbonates which may settle out in the system; and (2) absorption of water vapor to form alkali metal hydroxides. These reactions do not interfere with process operation but if allowed to continue will ultimately affect utility of the system. They may be eliminated by blanketing the molten salt with nitrogen.
Ordinary carbon steel may be used successfully in molten-salt equipment up to 454% (850’F). Above this temperature more resis- tant alloys are recommended. Copper equipment has been used sat- isfactorily at moderate temperatures, 316V (SOO’F), but cast iron is not recommended because of a reaction between the molten salt and the iron which results in embrittlement or fissuring.
Mineral oils Conventional mineral oils are of low cost and read- ily available for process use and are valuable in systems operating from - 1.1 to 316°C (30 to SOO’F). They need not be pressurized in this range. The paraffinic-type cylinder oils are often employed in open systems to about 232’C (450°F), such as are used in tempering metal. At higher temperatures the conventional mineral oils are used in closed systems, up to 316’C (SOVF), in which temperature region the oils become susceptible to thermal cracking. This decomposition, similar to the controlled cracking process used to produce gasoline from heavy oils, is not nearly so severe as the cracking that occurs in petroleum refining but will produce volatile materials that reduce
TABLE 9-54 Ph+cal Prowrties of Thermal Fluids
Specific gmvity at 212’E : Melting point, “F. Boding point. ‘F. (am. prarure, Flub pint. COC. ‘F. Speeik heat of hquid. B.t.u.;&F.) : : : Hut of vqmiutio”. B.t.“./lb. Heat of fusion. B.l.u./lb. Cube,1 erpmi”” coeffiwnt : : : Absolute vkccsily of liquid. centipoise Surface term” (cantact with ati). dynes/cm. Thmal cmductiwty hqud. B.t “.,(hr.)(q. h.~‘F./R.)
18 0.958
32 212
l.OWZ12”F.) 970.2 143.3
Oar24 0.2B4(212’F.1
72.8 0.393
Dowthem A’
165 0.997 53.6 495.8 255
O.S28(496’F 125.0 64
O.maU O.LW&WO’F
43 0.078 I .)
)
Dowtherm E’
WK’,
147 1.191 -6.7 352
0.4,2$2’F 119.0 39
0.30(4OO’F. 37
0064
Fused Salt HI Tect
NsNO, NaNO, KNO,
92 1.9!,(3OO’F.)
288 .,..........
0.373000’F.)
35 O.lXO20
1.7(BWF.)
035
011 Oil Mobiltherm Mobiltherm
6001 Ii&t
0.90 20 (po”, point)
>@JO
0.5BO$%F )
0.930 -20 (pour point:
>a 250
0.5WOO’F.)
O.ooo35 O.XS&WO’F)
OClKl35 0.87&300’F.)
0.067 0.0652 t
Hydr”thern$ 75wxm
1.11 5 (P” P”“Q
475 O.Wrn’L)
0.572z0’E’ O.OYN
Hydrotherm$ Therminoll 700-180 FR-2
Hg 44 wt.% K
108 40 (pw p0i.q
,..... 0 64(5OO’F.)
1.38 20 (p”“’ paint)
644
,.33.$&F.)
0 6tW0O’F.l O.OOlU9
0.63(5OO’F.)
0.972 0.057
‘The Dow Chemical Company.
f E. I. du Pont de Nemoun h Co.. Explosives Department, Wilmington, De1 1 Mobil Oil Corp. QAmerican Hydrotherm Corp. 1 Monsanto co. NOTE: To convert British thermal “nits per pound-degree Fahrenheit to joules per kilogram-kelvin. multiply by 4.187 X Id; to convert atmospheres tokilograms
per square centimeter, multiply by 1.0333, to convert British thermal units per pound to kilojoules per kilogram, multiply by 2.326; to convert centipoise to grams per centimeter-second, multiply by 0.01; and to convert British thermal units per hour-square fee-degrees Fahrenheit per foot to watts per square me!e-kelvin.
multiply by 5.678. “C = (“F - 32) X %.
Mercury NaK
9-78 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
the flash point of the oil. At the same time, the decomposition yields heavier products, which after long periods of operation flow less readily, leading to formation of coke deposits.
Mobiltherm 600 and Mobiltherm Light (Mobil Oil Corp.) are aro- matic mineral oils of lower viscosity than conventional mineral oils and can operate between - 1.1 and 316% (30 and SPOOF) for the former and at -25°C (-15’F) but not above (400°F) for the latter. They will not be broken down by temperature when used in the rec- ommended range. Their tlash points thus remain unchanged after many hours of service life. When the aromatic oils are subjected to excessive temperatures, thermal cracking will occur in a form similar to the decomposition of conventional mineral oils. Sludge and coke deposits do not readily occur with such aromatic mineral oils, as they have a powerful solvent action, and some installations have operated for years without changing oil or cleaning the system.
Neither aromatic mineral oil is suitable for operation in an open system, in direct contact with air. Oxidation results in deterioration of the oil, a chemical breakdown that is accelerated when the oil is at an elevated temperature. All process systems must include a “cold- oil” expansion tank, in which the temperature of the oil will not exceed 54’V (130°F). The expansion tank prevents the hot oil of the process system from coming into contact with air. The aromatic oils should not be used with copper or copper-bearing-alloy parts, since these metals are powerful catalysts which promote oxidation and sludging. Iron and carbon are preferred for the entire system. Other oils, whether lubricating or mineral oils, should not come into contact with aromatic oils, as this causes the solvent power of the oil to be lowered and may result in harmful sludge being deposited in the system.
Silicon Compounds Three types of silicon compounds are in use as heat-transfer media: silanes, silicones, and silicates. Silanes are substituted hydrides of silicon; silane itself has the form SiH,. The silicone Euids in use are usually polymers. The basic structure is of the form Si-0-Si, with organic radicals attached directly to the silicon atoms. Silicates are the salts or esters of the silicon acid in which the central atom is silicon. The organic heat-transfer fluids are generally esters. The organic constituents usually comprise alkyl, aryl, or alkaryl groups.
Hydrotherm 750-200 is an arylaryloxy- (mixed) silane used at tem- peratures from 63 to 371°C (145 to 7GPF). It is a transoarent amber fluid with a slightly phenolic odor. There appear to be no chronic or other pathological effects from exposure to vapors; skin tests show dermatitic effects similar to those of phenol. The substance is lethal on injection or ingestion. There is negligible corrosion in ferrous met-
als, copper, and copper alloys. There is a slight attack on aluminum and magnesium metals.
Hydrotherm organosilicate heat-transfer tluids are applicable for heating and cooling operations from -4.56 to 357’C (-50 to 675OF). Since these lluids do not freeze and stay pumpable below -17.8OC (OOF), neither reheating nor steam tracing is required. Hydrotherm silicate heat-transfer tluids are noncorrosive toward mild steel and copper and its alloys, even at high temperatures. How- ever, magnesium, aluminum, zinc. titanium, and their alloys are attacked. Organosilicate liquids do not present a potentially serious fire hazard. Hydrotherm 700-160, a tetraaryl silicate, is an amber- colored liquid with a slight phenolic odor that has good thermal and chemical stability. It does react with oxygen, and so contact with the atmosphere should be avoided. In the presence of moisture hydrol- ysis takes place; free phenols are released and a silicate sludge is deposited. Thermally, a re-forming reaction occurs at elevated tem- peratures, above 357°C (675°F). Low-boiling products, primarily monohydric or dihydric phenols, are formed and a gradual increase in viscosity occurs.
Therminol FR heat-transfer liquids are a series of chlorinated biphenyls of increasing chlorine content. Many important physical characteristics such as viscosity, density, and pour point vary from lowest- to highest-molecular-weight members of the series. One rea- son for their succes as a heat-transfer medium is that they do not support combustion. Their spontaneous ignition temperature is about 649°C (1200°F). Therefore they can be considered fire-resistant. These compounds are relatively inert liquids, resistant to the action of water, dilute alkalies, dilute acid solutions, air, and oxygen. They are readily soluble in most of the common organic solvents and drying oils. All these &ids are stable below 316OC (600°F). At higher temperatures thermal decomposition takes place, higher polyphenyls are formed, gaseous HCI is liberated, and viscosity increases. The vapors at high temperatures are at a level of toxicity such that ade- quate provision must be made for ventilation when leakage occurs, and system vents should be remote from normal operating areas. Although the compounds are not severe skin irritants, they should not be in repeated contact with the skin. Because of its low pour point, Therminol-FR-2 is widely used at temperatures between 10 and 316V (50 and 6COOF).
Mercury is useful in thermal-liquid systems. Its stability as an ele- ment makes it suitable for high temperatures, in the range of 316 to 538OC (600 to lOC@F). Experimental work shows that it has no cor- rosive effect on metals commonly used in practice. Mercury is toxic to humans, and mercury systems must include elaborate precautions to prevent the escape of mercury vapor to the surrounding atmo- sphere. The low latent heat of vaporization of mercury makes it unattractive to use as a vapor at low temperatures when heat must be given up during condensation. The high cost of mercury, in com- parison with other thermal liquids commercially available, precludes it use at temperatures below 316V (6OOOF).
Sodium-potassium alloys are used for heat transfer instead of the pure elements because these mixtures have lower melting points. The two most popular alloys are, by masts percent, 56 Na-44 K and 22 Na-78 K. The latter is approximately the eutectic composition. In comparison with the pure elements, NaK alloys have a lower thermal conductivity, whereas vapor pressure, density, specific heat, and vis- cosity fall between values of the two elements. The chemical prop erties of NaK alloys are almost identical to those of sodium; however, the alloys are more reactive. Increased chemical activity can be ascribed to the presence of potassium, which has a greater reactivity than sodium. Upon contact with the atmosphere, potassium is oxi- dized to the superoxide, KOz; and explosions have been caused by reaction of the superoxide with hydrocarbon gases used as cleaning media. The use of hydrocarbons in NaK systems should be discour- aged. Experiments at 204OC (400°F) have revealed that sodium monoxide, rather than potassium superoxide, precipitates from NaK alloys. Other reactions of potassium not duplicated by sodium are an attack on silicon and the formation of an explosive carbonyl on con- tact with carbon monoxide. Carbon steel and low-alloy steels show good resistance to attack up to 538°C (lOCWF), and they can sup plant more expensive stainless-steel alloys. Oxygen impurities above
THERMAL-LIQUID SYSTEMS 9-79
ri li I B-?- 1 Temperature
1 controller,
I H
1 p.
Drains to storage tank
W. 9-92 Dowthem~ gravity-return system. V. C = maximum and mini- mum liquid levels in vaporiser drum; M, H = range of liquid heights in con- densate leg between A and B to cause flow through system. Dotted lines show the vapor path; solid lines, the liquid path. (Faster Wheeler Corp.)
100 ppm markedly accelerate corrosion. Alkali metals react with the skin and eyes, causing thermal and alkali burns. Oxide smoke or hydroxide mist is irritating and corrosive to the throat and lungs.
Toxicity Many instances of potential hazards have been described in this discussion of heat-transfer &ids, and this paragraph is intended to emphasize the problems. Toxicity and ecology are extremely important from both an operating and a process stand- point. There is always a chance that a beat-transfer fluid will leak from a system, e.g., packing glands on valves, pumps, and heat exchangers. If this happens, operators, maintenance personnel, and the environment in general may be overexposed to fluids known to be hazardous. Polychlorinated biphenyls (PCBs), especially, must be
used with great caution.
Process Systems
Dowtherm Dowtherm process sytems are either gravity-return or pumped-return. The most desirable system is the gravity system, in which the vapor rises from the vaporizer to the heated vessels, condenses, and flows back to the vaporizer by gravity. No moving parts are required. It is essential that the gravity-return-system pip ing be suitably proportioned to the limitations of the headroom avail- able between the bottom of the heated vessel and the liquid level in the vaporizer. This involves the frictional loss in the vapor piping, the user, and the condensate return. Figure 9-82 is a gravity-return system, and Fig. 9-83 shows the pumped-return system. Pumps should generally be of cast-steel construction with a deep water- cooled stuffing box designed for metallic-foil packing.
Transport of heat at two different temperatures may be accom- plished with Dowtherm in a single vaporizer by supplying the higher-temperature process with vapor and the lower-temperature process with Dowtherm liquid. Close control of the vapor tempera- ture is achieved by maintaining the pressure in the vaporizer, while the liquid temperature is controlled by circulating only part of the process returns through the heating unit. In such an installation, illus- trated in Fig. 9434, the Dowtherm vaporizer provides vapor at the desired temperature for two high-temperature users. A liquid- Dowtherm circulating system heats the low-temperature users. In this system, the hot liquid is withdrawn from the vaporizer and returned to it after passing through the heating elements of the ves- sels. A three-way valve, which divides the return-liquid flow, pro- vides automatic control of the liquid circuit. Part of this flow returns to the vaporizer to be reheated, while the remainder bypasses the vaporizer and flows directly to the circulating pump section. The amount of heat put into the liquid system is controlled by varying that part of the flow returning to the vaporizer.
As Dowtherms have extremely low surface tension and viscosity at high temperature, more than ordinary care is necessary in the fab rication and erection of equipment to prevent leakage. There is ordinarily more or less evidence of leakage at pump stuffing boxes, relief-valve outlets, etc. Welded construction in accordance with ASME specifications is advisable whenever possible. The wide range of temperature requires adequate provision for expansion of piping. The high temperature renders ordinary relief-valve springs unsafe, and only special tungsten-steel-alloy relief-valve springs are suitable. Other relief-valve parts and other fittings should be steel rather than brass or bronze.
The condensate line of a gravity-return system should include the *called Hartford loop. This consists of a line connecting the lower vaporizer drum and the vapor space above the upper drum. The con-
9-80 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
ermostat-controlled
st;;,“e$! charge Cwculcting
pump Pump
FIQ. 9-U Combination vapor and liquid heating with Dowtherm. (Foster Whm&r Corp.)
densate return is brought into this line at a point just above the top of the tubes in the vaporizer. With this loop it is impossible to draw liquid out of the vaporizer up through the condensate line after the liquid level in the vaporizer falls below the point at which the con- densate line enters this connection. If the liquid level is drawn lower than this point, vapor will be drawn back into the condensate line, and the resulting water-hammer effect will give warning that the liquid level is too low.
Other recommended safety features include installation of a stor- age tank of sufficient capacity to contain the entire system charge. It should be buried or otherwise located where not exposed to fire. The drain valve from the vaporizer should be accessible so that, in the event of an uncontrollable vaporizer fire from a tube leak, the liquid in the vaporizer can be drawn off promptly. Emergency drainage of the vaporizer requires considerable judgment, however, since dam- age to dry heating surfaces from burning fuel may cause consider- ably more damage than would result from a relatively small Bre or tube leak.
Recycled Dowtherm needs no treatment to maintain purity. Peri- odic analysis is recommended to detect contamination or deteriora- tion Repurification requires shipment of the complete charge to the reprocessing plant. For this reason remote locations ftnd it economi- cal to install continuous-reclamation equipment in the process plant.
Zmrganic Salts Inorganic-salt mixes are heated electrically for pilot-plant units and for larger processes in gas- or oil-fired units with capacities up to 4396 kW (15 million Btu/h). They may be either fire-tube or circulating furnace design. In each design the initial charge is melted by means of steam coils or electric immersion heat- ers. For moderate heating applications, to about 316% (6CU’F), an
Ao. 9-85 Fire-tube salt-bath heater. (E. I. du Pant de Nemours G Co.)
indirect salt-bath heater, including both the molten salt and a flow coil for the product to be heated, is placed in a ftre-tube design (Fig. 9-85). Gases passing through the fire tube maintain the salt in a mol- ten state with precise control over the temperature of the product passing through the Bow coil. Advantages for this indirect heater are its safety of operation, even heat distribution to the tlow coil, high efficiency, and elimination of Bow-coil failure because of flame impingement or localized overheating. The maximum size of these heaters of 2344 kW (8 million Btu/h) can be supplemented by installing several heaters in battery fashion.
Heating and cooling are accomplished in one unit, shown in Fig. 9-86, for processes in which reactions taking place at a high temper- ature level require removal of exothermic heat. Once the salt initi- ates the exothermic-process reaction, it maintains the reaction tem- perature by switching the flow of molten salt from the heating unit
RG. 9-w Circulating-salt system for heating and cooling operation. (Beth- lehem Corp.)
to the steam generator that is mounted integrally with the heating unit. By means of a three-way valve, all or a portion of the salt flow can go to the cooler. Controls on the system maintain temperature levels by forestalling pump operation when the salt temperature falls below the desired level and sounds an alarm if the salt temperature exceeds a safe limit of the process.
because of the high melting point of the inorganic-salt mix, salt lines and valves must be traced or steam-jacketed to prevent freezing by solidified salt, especially for intermittent operation. Submerged centrifugal pumps are used to circulate the salt and are of a type which permits no contact of the salt with the packing gland.
Remelting of salt, or fusing of the initial charge, is done with elec- tric immersion heaters or steam coils that pass below the surface of the bath. Heating a solid bath of salt from the bottom alone can develop sufficient pressure to rupture equipment or expel the molten salt through the solid surface.
Combustible solids, such as wood, coke, paper, plastics, cyanides, chlorates, and ammonium salts, and active metals, such as aluminum and magnesium, are potential hazards. Magnesium, except as an alloying agent in low concentration, must not come in contact with the salt mix. The salt itself is not flammable but will support com- bustion Water from spray sprinklers or low-velocity fog nozzles is recommended as fire protection.
Mineral Oib Conventional mineral oils are not affected by con- tact with air at temperatures of about 232OC (450°F), but aromatic mineral oils must always be used in a closed system with a cold-oil expansion tank to prevent the hot oil from contact with air. Figure 9-87 is a layout for indirect heating with hot-oil recirculation.
The heater may be direct-fired, with combustion gases passing over the tubes through which the heated oil circulates, or electrically heated, with the oil Rowing through narrow channels over the heat- ing source. Other heater designs utilize high-temperature steam pass- ing through heating coils with the circulating oil outside. The heat source must be such that excessive temperatures are avoided. Large heating-surface areas and moderate temperature differences between the oil and the heat source are preferred to minimize ther- mal breakdown of the aromatic oil. In electric heaters this is achieved with a power input of not more than 1.9 W/cm* (12 W/in’) of heat- ing surface; for oil- or gas-fired radiant heaters the input should not exceed 126 to 158 kW/mx [40,000 to 50,OCQ Btu/(h’fta)] of coil surface.
All hot-oil systems use forced circulation because of the absence of gravity-head differences between heated and cooled oil. Centrif-
ugal pumps are usually supplied with exterior lubrication of the shaft bearings to prevent lubricating oil from entering the system. The pump should have sufficient capacity to provide a velocity through the heater of not less than I.2 m/s (4 ft/s) for oil temperaures up to 204°C (400°F) and about 3.05 m/s (10 ft/s) for 204Y (600°F).
A thermostat maintains the desired temperature in the process ves- sel and acts to cut out burners or electric current in the heaters when oil temperatures rise too high. To prevent constant on-off switching of the heaters a relief valve is supplied to act as a bypass and main- tain a constant flow of oil through the pump and heater when the thermostat reduces the Bow of hot oil to the processing vessel.
Reuse of aromatic mineral oils is continuous, with losses from the system being replaced by identical oil added to expansion tank or pump suction, Periodic analysis and comparison with initial proper- ties will determine service life.
Therminol Fluids Two basic heater designs for Therminol fluids are available: the liquid-tube types and the fire-tube types. In the former, the Therminol is pumped through the tubes at a definite Bow rate as it is heated. In fire-tube types, the fluid flows through the shell. When operating temperatures above 260°C (5CPF) are required, a liquid-tube-type heater is preferable unless a specific design is devised to force a steady flow over the heat-source surface. The fluid should be pumped over the heating surface so that no areas of stag- nant fluid which might present hot spots occur. The fluid velocities over the heat-sour. e surface should be in in the range of 1.2 to 3.05 m/s (4 to 10 ft/s). When electric heating is used, maximum energy density should not exceed 1.6 W/m* (10 W/in*) at the minimum velocity, although 3.2 W/m* (20 W/in’) can be used with proper design and sufficiently high velocity.
For large how rates, the iluid circulating pump should generally be the centrifugal type. When gear pumps are used, care should be taken to select a capacity that will give adequate Bow through the heater even after wear. If expansion loops are used in the pump suc- tion piping, they should be arranged to prevent trapping air or noncondensables.
Like most organic liquids, Therminols expand in volume by about 4 percent per 37.8OC (lOOoF) temperature rise.Thus, in heating from room temperature to 3IfYC (66VF), the tluid in the system expands by about 20 percent. The expansion tank must therefore accom- modate this increase in total tluid volume; doubling the minimum size is recommended It should be on the pump suction side, above the highest point in the system, and should be connected to the sys- tem by a sufficiently small line to avoid thermal recirculation. Major venting can be done from the expansion tank. The vent should be outdoors, away from working areas. The entry of atmospheric mois- ture on “breathing” should be prevented by use of an air dryer, such as a calcium chloride pot or other desiccant. An alternative would be to blanket the expansion tank with nitrogen, but this system must be thoroughly dried.
In systems using Therminol above 316OC (600°F), some provision must be made to vent any HCI gas formed in the system and to assure that the system remains dry. It is advisable to provide a pipe to feed a small sidestream of hot Therminol from near the pump discharge to the vented expansion tank, above the highest liquid level. It is advisable to trace and insulate the expansion tank and vent so that any moisture accidentally entering the system will remain as yapor and not condense.
COGENERATION
Definition and General Description Cogeneration is an energy- production process involving the simultaneous generation of thermal (e.g., process-steam) and electric energy by using a single primary heat source. It can be employed whenever there is a need for the two energy forms and whenever on-site electric power generation is jus- tified or when thermal-energy users are in close proximity to an elec- tric-power-generation site.
Industrial use of cogeneration leads to small, dispersed electric- power-generation installations-an alternative to complete reliance on large central power plants. Because of the relatively short dis- tances over which thermal energy can be transported, process-heat
9-82 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
generation is characteristically an on-site process, with or without cogeneration.
Fuel saving is the major incentive for the use of cogeneration. Since all heat-enginebased electric power systems reject heat to the environment, that rejected heat can frequently be used to meet all or part of the on-site or local thermal-energy needs. Use of rejected heat usually has no effect on the amount of primary fuel used, yet it leads to a saving in all or part of the fuel that would otherwise be used for the thermal-energy process. Heat engines also require a high-temperature thermal input and in some situations can obtain the input thermal energy as the rejected heat from a higher-temper- ature thermal-energy process. In the former case, the cogeneration process employs a heat-engine topping cycle; in the latter case, a bot- toming cycle is used. The fuel-savings benefits in a topping-cycle configuration are illustrated in Fig. Q-88.
&generation systems can be designed from at least two perspec- tives: they can be sired to meet the process-heat needs of industrial or institutional users, so that the electric power produced is treated as a by-product which must either be used on site or sold to the local utility; or cogeneration systems can be sired to meet electric power demand, and the rejected heat is then used to supply process-heat needs at or near the site. The latter approach is the likely one if util- ity ownership is involved.
Furthermore, cogeneration systems will usually not match the varying power and heat demands at all times for most applications. Thus, a cogeneration system’s output frequently must be supple- mented by the separate on-site generation of heat or the purchase of utility-supplied electric power. Another option is the sale of excess locally generated electric power to the local utility grid-a situation which can occur when the cogeneration system is matched to the heat load and on-site electric power demand is low. These options for on-site power and heat use are also illustrated by Fig. Q-88.
Fuel-use options for cogeneration systems are determined by the primary heat-engine cycle. Closed-cycle power systems which are externally fired, such as the steam turbine, the indirectly fired open- cycle gas turbine, and the closed-cycle gas-turbine power system, can use virtually any fuel which can be burned in a safe and environ- mentally acceptable manner; fuels such as coal, municipal solid waste, biomass, and industrial waste are burnable with closed power systems. Internal-combustion engines, such as diesel engines and open-cycle (combustion) gas turbines, are restricted to fuels which have combustion characteristics compatible with the engine type and which yield combustion products clean enough to pass through the engine without damaging it; refined liquid and gaseous fuels derived from petroleum, shale, coal, or biomass are included in this category. These heat engines and fuel options are illustrated in Fig. 9-89.
Off-site waste _ + On-site heat*-
/ > O,I!/?)e-1)
I ,-~>(OH-OHE)X
,A (1+,-l) , Recoverable
Process waste heat J
zoce demand.
OHE -.---7 /
OH
*Includes combustion stock losses. ’ \ \- t ~+GiGt3 Ke%tt - ’ I .____________---/ Useful relotlons
Key I)= energy convewon
efficiency
0 = energy flow
Ro= power-to-heat ratlo for the load demand (R,= OE/O"l
RHE= power-to-heat ratio for the heot engine
tRHE =OE”E/%EI
Supplemental energy flows: Case 1' heotenoine matched
to elec&ic demand. Of, ond R,,>R,:I~X>
Cose2: heotenglne matched toheot demandLOu, and R,E< R,:_.:'X
Parameter Convention01 Cogenerotion opprooch
opprooch (~IOE~~=OE;RHE>R~; (210,E=0,;R,~<Ro
Totol fuel used. OF
Ro. 9-U Illustrative fuel savings with cogeneration.
COGENERATION 9-83
There are at least three broad classes of application for topping- cycle cogeneration systems:
. Utilities or municipal power systems supplying electric power and low-grade heat (e.g., 149”C, or 300°F) for local-district heating systems
. Large residential, commercial, or institutional complexes requir- ing space heat, hot water, and electricity
* Large industrial operations with on-site needs for electricity and heat in the form of process steam, direct heat, and/or space heat
Typical Systems All cogeneration systems involve the operation of a heat engine for the production of mechanical work which, in nearly all cases, is used to drive an electric generator. The most com- mon heat-engine types appropriate for topping-cycle cogeneration systems are:
- Steam turbines (back-pressure and extraction configurations) - Open-cycle (combustion) gas turbines . Indirectly fired gas turbines: open cycles and closed cycles . Diesel engines Each heat-engine type has unique characteristics making it better
suited for some cogeneration applications than for others. For exam- ple, engine types can be characterized by:
. Power-to-heat ratio at design point
. Efficiency at design point * Capacity range
TABLE 9-55 &generation Characteristics for Heat Engines
Heat-rejection alternotwes
. Power-to-heat-ratio variability
. Off -design (part-load) efficiency
. Multifuel capability The major heat-engine types are described in terms of these char-
acteristics in Table 9-55. Representative cogeneration systems appropriate for each engine
type are described in the following paragraphs. Steam-Turbine Systems Both back-pressure and extraction-
condensing steam-turbine systems can be used in cogeneration appli- cations. Typical configurations are illustrated in Figs. 9-90 and 9-91. The back-pressure configuration is better suited for applications in which the power-to-heat ratio is low and relatively fixed. Extraction- condensing steam turbines offer greater variability of power-to-heat ratio (through changes in the amount of extracted steam) and a higher power-to-heat ratio (when extracted steam is minimized). The extraction-condensing cycle must always condense the steam Bow which passes through the full-pressure ratio of the turbine; the extracted steam may or may not need to pass through the condenser, depending on the temperature limits of the heat load and whether or not it condenses the steam Row. For the back-pressure configura- tion, the need for a condenser, separate from the heat load, depends, first, on whether the spent steam is available for recycling to the steam generator, and second, on whether the heat load itself conden- ses the steam flow.
Engine type
Steam turbine Extraction-condensing type
Size range, MWe/unit
30-300
Maximum temperature Efficiency at Part-load Multifuel of recoverable heat, design point efficiency capability OF(“C)
0.2-0.30 Fair Excellent 200 @!3)-600 (315H
Back-pressure type Combustion gas turbines Indirectly fired gas turbines
lo-85 0.25-0.30 PO01 Good 700 (371)~900 (482) 5-350 0.25-0.30 Excellent Good 700 (371)~900 (482)
Recuverable Typical
he&fltu’ power-to-heat
0 ratio
ll,OOO- 0.1-0.3
35.000 17,Oca70,000 0.05-0.2
3090-11,000 0.3-0.45
35wa500 0.4-1.0 35Ow35a 0.4-1.0 4000-6000 Ox-O.85 Diesel en&es 0.05-2.5 0.35-0.40 Good Fair to poor 500 (260-700 (371)
‘1 Btu = l&5]. tsaturated steam
9-84 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
t STOCk w
--, Electric power
Pump power
FIG. 9-90 Extraction-wndensing-steam-turbine cogeneration cycle. CB = combustor; P = pump; T = turbine; --- = cycle options.
Gas-Turbine Systems Gas turbines operate on the Brayton ther
modynamic cycle: adiabatic compression, isobaric heating, adiabatit expansion, and isobaric cooling. Gas turbines may be either of thl combustion or the indirectly fired type. In a combustion turbine : clean fuel’ is burned directly in the compressed-air working fluid and the combustion products are then expanded through the turbin and exhausted to the atmosphere. Indirectly fired turbines receiw their thermal input via an external combustor and a heat exchanger so that none of the combustion products pass through the turbine The combustion turbine must be an open cycle; that is, one in whicl the working fluid (in this case, air mixed with combustion product in the turbine) is not recycled and compressor inlet and turbin exhaust are at atmospheric pressure. Indirectly fired gas turbines dc not contaminate their working fluid with combustion products ant can therefore recycle the working &rid, allowing the cycle to b either open (to the atmospheric intake and exhaust) or closed. Closet gas-turbine cycles offer distinct advantages in terms of choice o working fluid and system pressure level. The two classes of gas-tur bine co eneration systems are illustrated in Figs. 9-92 and 9-93.
Corn Ls tton gas turbines. The combustion-gas-turbine systen (Fig. 9-92) provides a higher power-to-heat ratio than typical steam
‘Usually a gas or light liquid with virtually no ash, sulfur, or heavy metal present.
tor; P = pump; T = turbine; --- = cycle options. figuration shown). C = compressor; CB = combustor; T = turbine.
5
CB
$ir?i! C T
Recuperator
& . I tieot
load
FIG. 9-93 Combustion-gas-turbine cogeneration cycle. C = compressor; CB = combo∨ T = turbine.
turbine configurations (see Table 9-55). Of all systems considered, the combustion gas turbine also provides rejected heat at the highest temperature [up to 650% (12OO’F)j However, the waste heat in the turbine exhaust cannot generally be used directly, because of the presence of combustion products, and must be removed by means of a heat exchanger or a boiler. While low in capital cost, combustion gas turbines have the drawbacks of poor part-load efficiency and the requirement for clean fuel to avoid erosive or corrosive damage to the turbine.
Indtwctly fired gas turbines. Indirectly fired gas turbines avoid the problems of fuel sensitivity of combustion gas turbines. Other- wise, the major advantage of indirect firing is the possibility of using a closed- (pressurized-) cycle configuration. Closed-cycle gas tur- bines, as illustrated in Fig. 9-93, can be coupled to a gas-management system which adjusts the working-tluid inventory (hence, mean pres- sure level) so that load tluctuations can be accommodated with little or no loss in efficiency. This latter feature is a consequence of the fact that load variations are met by changes in density without the need to change temperature, pressure ratios, or relative velocities in the turbomachinery.
Power-to-heat-ratio variations over a relatively wide range (see Table 9-55) are accommodated by varying the recuperator-bypass- Row fraction. With no recuperator bypass, a maximum power-to- heat ratio is obtained. Combustion gas turbines may similarly be recuperated (see Fig. 9-92).
Diesel Engines Diesel engines have long been used in small- scale (e.g., l- to lO-MWe) cogeneration applications. They are char- acterized (see Table 9-55) by high engine efficiency, good part-load
Electric
Open-cycle OptIon
*For closed- cycle Only
COGENERATION 9-85
Heat (h@
t
Stock qos (exhaust)
,Electric Dower
Heat load (low temp.)
FIG. 9.94 Diesal-engine cogenerntion cycle
characteristics, a relatively low rejected-heat temperature, and a high power-toheat ratio. As an internal-combustion engine (the working iluid is, in part, made up of the combustion products), the diesel offers only a limited tolerance for fuel variability.
Diesels supply heat in two forms: low-temperature (93 to 121°C, or 200 to 25O’F) engine coolant; and higher-temperature (260 to 371”C, or 500 to 7OPF) exhaust gas. The diesel engine as a cogen- eration system is illustrated in Fig. 9-94.
EnergySaving Potential The energy-saving potential of an on- site cogeneration system can be analyzed in the manner illustrated by Fig. 9-88. An on-site energy demand for electricity and process heat is conventionally met through the purchase of electric power, generated by an off-site heat engine (usually a steam-turbine cycle) at a central utility, and the burning of fossil fuel in an on-site boiler- steam generator. When cogenerating, an on-site heat engine supplies all or a portion of the electricity demand, while the heat demand can be supplied, at least in part, by the rejected heat from the heat
The fuel-saving potential for a heat engine having an efficiency [from fuel (HHV)’ input-to-shaft power output1 nx can best be esti- mated by the overall efh‘ciency [fuel (HHV) to-useful work and power] nm of the cogeneration cycle, which is, in turn, a function of
‘High heating value.
the power-toheat ratio R supplied by the heat engine. This relation- ship is given by
and is plotted as a function of A, for fixed values of vs. in Fig. 9-95. For large values of Ii, nw approaches nx, as the useful-heat portion of the engine output goes to xero and the engine reverts to a conven- tional, noncogenerating operating mode. For low values of R, 7, rises to unity as the power-to-heat ratio drops to the minimum value R mi”, when all the rejected heat from the engine is fully utilized. R,, is given by
&II - ‘Ix/(1 - 9x) (9-48)
Equation (9-48) applies to an internal-combustion engine, such as a combustion gas turbine or a diesel engine, or to an external-combus- tion (i.e., indirectly fired) engine in which all rejected thermal energy, relative to the ambient reference, can be removed, including the energy in the stack gases from an external combustor. In most cases it is not practical to extract 100 percent of the available thermal energy, especially from the combustion-product stream of a dirty- fuel combustor. If that combustor has an efficiency [fuel (HHV) to heat delivered to cycle working fluid] ns, then the maximum overall efficiency is ~)a, not unity, and the minimum value for the power-to- heat ratio R,, for such an external combustion cycle is given by
ILL,, = tlE/(% - I)E) (949)
For the cam of a heat-engine efficiency of 30 percent, including com- bustor losses as defined by a value of ns = 0.85, values for A,,. and A& are illustrated in Fig. 9-95.
Figure 9-95 is useful as a means for estimating overall-fuel-use effi- ciency and its dependence on the delivered power-to-heat ratio for a given heat-engine efficiency. It is not intended as a substitute for a cogeneration-performance prediction for a particular cogeneration system. The limitation of Fig. 9-95, in this regard, is due to the fact that for most of the heat-engine cycles considered here (the diesel engine being the exception) the efficiency of the heat engine nx is a function of the power-to-heat ratio R. For instance, the engine effi-
r)~= Heat-enqlne effnency, fuel (HHV)to shaft power
~~=Combustor efflclency
I I I I I I I I It, I I I
0.5 1.0 1.5 2.0
~0.9-95 overall efficiency of a heat engine in cogeneration mode.
Power-to-heat ratio, 13
9-86 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
ciency of an extraction-condensing steam turbine (Fig. 9-91) is a 8, the zeropower throttle-tlow fraction representing leakage and strong function of how much steam is extracted and at what pressure recirculation losses within the turbine level. A similar argument applies to gas-turbine cycles in which the To use such a performance map, the value of the extraction-flow recuperator-bypass-flow fraction is varied to accommodate a chang fraction r is first determined so that the heat demand is satisfied (r ing power-to-heat demand. Typically, heat-engine efficiency vE cannot exceed 1.0; if the heat demand requires T to be >l.O, then decreases as the demand for heat rises (R decreases), and heat-engine supplemental heat must be supplied). For the defined extraction-flow performance must be compromised to meet it. Such a characteristic fraction r, the throttle flow ff is set to deliver the required power, is illustrated in Fig. 9-95. subject to the constraints on maximum and minimum turbine power
Cogeneration Performance of Representative Systems The output for a given value of r. engineer designing a cogeneration system for a particular application The performance of an extraction-condensing steam turbine in a must analyze the performance capabilities of the most appropriate typical cogeneration application is illustrated in Fig. 9-97. heat-engine types, selected on fhe basis of the characteristics listed in Zndirectly Fired Gas Turbine The performance of an indi- Table 9-55. Examples for two-engine types, an extraction-condensing steam turbine and an indirectly-fired-gas-turbine cycle, both chosen
rectly fired gas turbine with variable recuperator bypass as a means for matching a power-to-heat-ratio variation is illustrated in Fig. 9
because of their compatibility with coal firing, are presented in the 98. The illustrated cycle schematic is for a closed cycle gas turbine. following paragraphs, However, the performance envelope is applicable also to open cycles
Extraction-Condensing Steam Turbine The performance of a (which would have no cooler or cooling heat load Q.) with the same representative extraction-condensing steam turbine, allowing for variable extraction to permit variation in the delivered power-tc+heat
ratio, is illustrated in Fig. 9-96. The performance envelope is seen to Since the assumed combustor efficiency is 0.85, this value marks be specified by:
fa the full-throttle flow for no extraction the upper limit on overall efficiency (refer to the discussion for Fig.
7, the ratio of maximum-extraction Bow to full-throttle flow, f0 $95). Overall efficiency is determined as a function of the power-t* heat ratio A, recuperator-bypass fraction A, and gas temperature T,
IM and 7~. the efficiencies for the high- and low-pressure portions of the turbine
at the exit of the heater supplying the useful heat load Qw. In a par-
hl, hb, hb,, the isentropic enthalpies defined by the steam-supply titular cogeneration application, the power-to-heat demand ratio can
conditions (state l), the extraction conditions (state 2). and the con- be supplied by a range of combinations of recuperator bypass frac- tion A and heater exit temperature T,. However, the desired oper-
densing conditions (state 3) ating parameters are given by that combination of A and T, which
l Turbine efficiencies: high . Turbine inlet, 15OOOF (816’Cl . Combustor efficiency. 0.85
pressure. 0.70; low pressure, 0.80
l Compressor inlet, 8O’F (27”CI l Pressure-loss ratio, Aplp: 0.05
Condenser pressure 12 InHg (3.5kPa) l Efficiencies: compressor, 0.86;
turbine: 0.91
l Working flud. ow
0 9
I ST;;:,enerotor pinch 50°F
0 I I
0.5 1.0 1.5
Power-to-heat ratio, Ri
RQ. 9-W Compamtive performance of steam-turbine and gas-turbine (indirectly fired) mgeneration cycles supplying 16PC (330°F) steam and electric power.
- - --- Process-steam demand
:I, -EElectr~c-power demand
:-> I
L__ ----.-Power-to-heat ratlo I
- 500
- 400
r 3
;
“0 - 300 -.
P
% ;, 1.0
;200 al E - ;, 0
:
‘;
- 0.5 :
- 100 _ &
_ &
_ B
LO 20 ‘1: M 1 2 3 4 5 6 7 6 91011 N 12 3 4 5 67 8 9101
Hour of the day
Ro. 9-100 Typical power end heat demand for P typical fall weekday in P large institutional complex. l@ Btu/ h = 1.055 X ld J/h; 14 kWh/h = 3.143 X 10e Btu/h thermal equivalent.
HEAT RRGENERATION 9-89
just satisfies the requirement that the heat Qw be supplied with no less than a specified minimum temperature difference (called the “pinch”) between the gas-turbine working tluid, which is being cooled, and the heat-supply-system fluid (usually water or steam), which is being heated.
Comparative Performance of Steam and Indirectly Fired Gas-Turbine System As noted in Table 9-55, gas-turbine systems can be expected to operate at higher overall efficiency for a given power-to-heat ratio than will a steam-turbine system; conversely, for a given overall efficiency, a gas turbine will yield a higher delivered power-to-heat ratio than will a steam-turbine cogeneration system. This comparison is illustrated in Fig. 9-99, in which the two cycles described by Figs. g-969-97, and 9-98 have been compared as they supply electric power and 166’C (330OF) steam in varying propor- tions. For a given power-to-heat ratio, the gas turbine yields an over- all efficiency 15 to 18 points higher than that of the assumed steam cycle. Similarly, to achieve an overall efficiency of 0.60 or greater, the steam turbine is restricted to power-to-heat ratios of less than 0.375, whereas for the same efficiency limit the indirectly fired gas turbine can realize power-to-heat ratios as high as 1.0. Thus, the major determinant in whether a gas or a steam turbine is the more appropriate is not the efficiency but rather the power-to-heat ratio which the system must supply.
In addition, if the gas-turbine cycle is a closed (pressurized) cycle, it offers the additional very valuable feature of accommodating large load swings (down to I5 to 20 percent of design power level) with no significant effect on efficiency. As noted earlier, this benefit is achieved by virtue of the ability to change working-fluid inventory (and, hence, pressure level) in the system. Finally, closed-cycle gas turbines also offer the benefit of selection of working fluids (other than air) which may yield enhanced turbine and heat-exchanger performance.
Operational Issues
Varying, Noncoincident Load Demands for Power and Heat For most practical cogeneration applications, the demand for heat and power varies considerably during the course of a typical day. Such a variation for a typical large institutional complex is illus- trated in Fig. 9-100. For a cogeneration system to meet the entire power and heat demand for the typical day shown, it would have to have the following performance range capability:
. Power-to-heat ratio R, 0.31 to 0.84 * Power level, 38 MWe (at R = 0.31) to 79 MWe (at R = 0.84) If an extraction-condensing steam-turbine system were chosen for
this application, it could not efficiently meet the high power-to-heat demand portion to the daily load; either the system would be designed to meet the steam demand, in which case large quantities of electric power would have to be purchased during the middle of the day, or the system would be designed to meet the electrical load, in which case system efficiency would be greatly reduced during the high-power-to-heat-ratio portion of the day.
On the other hand, an indirectly fired gas turbine could efficiently meet (at >60 percent overall efficiency) all the heat and power demand except, possibly, in the early morning hours, when the power-to-heat ratio dips below 0.35. In this case, the system can be designed to meet either the steam demand, while selling excess power to the utility during the period from 1 to 5 A.M. (when the utility is least likely to want it), or the power demand, while supply- ing the small unsatisfied steam demand with a separate fired boiler.
Cost Considerations Ultimately, cost saving is the oblective in most cogeneration installations. The exceptions are those applications which are remote from utility power grids or which have special reli-
20
56% Fuel-cost sownqs for R = 0.8. ‘IE = 0.3, CR = 6
0 1 2
Power-to-heat mt10. R(- I
FIG. 9-101 Fuel-cost savings for heat-engin&s.sed cogeneration systems.
ability or security concerns (e.g., military installations, hospitals, etc.). Cogeneration involves additional fixed costs associated with buying and maintaining a larger, generally more complex, on-site physical plant. Against this added hxed cost can be traded the reduc- tion in total fuel costs when purchased electricity is considered a high-grade fuel for on-site use. The reduction in total fuel costs must be greater than the increased annualized fixed cost associated with the cogeneration plant in order to justify the facility economically. While a treatment of capital costs for various cogeneration alterna- tives is beyond the scope of this subsection, an analysis of fuel-cost savings, as a function of fuel-price ratios and cogeneration-system parameters can be useful. Figure 9-101 presents the fractional reduc- tion in total fuel costs (purchased electricity plus fossil fuel burned on site) as a function of power-to-heat ratio, heat-engine efficiency, and the ratio of electricity to fossil-fuel cost on a thermal equivalent ($/Btu or $/J) basis. By way of illustration, a cogeneration applica- tion with a power-to-heat ratio of 0.8, using a heat engine at 30 per- cent efficiency, with a fuel-cost ratio of 6, would realize a fuel-cost- saving fraction of 0.56. or 56 percent.
HEAT REGENERATION
Storage of heat is a temporary operation since perfect thermal insu- liquids as sensible or latent heat to be released later at designated lators are unknown; thus heat is temporarily absorbed in solids or times and conditions. Examples of collecting and releasing heat on a
9-90 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
Cc)
FIG. q-102 Checkerwork designs.
batch or continuous basis are the checkerwork regenerator for blast furnaces as a batch operation or the Ljungstrom type as a continuous operation. Recuperators are covered in the discussion on heat-trans- fer equipment (Sec. 11).
Checkerbrick Regenerators Preheating combustion air in open- hearth furnaces, ingot-soaking pits, glass-melting tanks, by-product- coke ovens, heat-treating furnaces, and the like has been universally carried out in regenerators constructed of fireclay, chrome, or silica brick shapes. Although many geometric arrangements have been used in practice, the so-called basketweave design shown in Fig. 9- 102~ and b has been adopted in many applications.
In blast-furnace stove construction, standard 22.9- by 11.4- by 6.4- cm (9- by 4.5- by 2.5-in) firebrick, assembled in basketweave design, forms square flues 8.3 by 8.3 cm (32.5 by 3.25 in) (Fig. 9-102n). In open-hearth regenerators, 46 by 15- by 7-cm (la- by 6 by 3-m) tiles form flues 19 by 19 cm (7.5 by 7.5 in) (Fig. 9-102b). Special shapes have been devised for more complicated, if frequently less rugged, heat-absorbing elements, e.g., coke-oven tiles (Fig. 9-102c). Standard firebricks are cheaper than special shapes, and this fact has
To chimney
Ro. 9-103 Blast-furnace stove.
,’ I Checker work
, Combustion I
chamber
, Hbter cooled wtve /
iif= -Hot blast
A* H Burner
%- + Gas
tended to confine regenerator design to the readily available and less expensive standard refractories.
Blast-Furnace Stoves A typical blast furnace, producing 1650 tons of pig iron per day, will be blown with 47 m3/s (lCCt,OOO stan- dard fts/min) of atmospheric air, preheated to temperatures ranging in normal practice from 482 to 649OC (900 to 1200°F) with 538’C (1000°F) close to an average. To preheat this blast volume, a set of four stoves is usually provided. A vertical and horizontal section of one such stove is shown in Fig. 9-103. Each stove consists of a vertical steel cylinder 7.3 m (24 ft) in diameter, 33m (110 ft) high, topped with a spherical dome. A side combustion chamber is separated by a bridgewall with a lens-shaped horizontal cross section. The remain- ing volume is filled with heat-absorbing checkerwork.
The heat-exchanging surface in each stove is just under 11,506 m* (124,096 ft*). In operation, each stove is carried through a two- step 4-h cycle. In one 3-h “on-gas” step, the checkers are heated by the combustion of blast-furnace gas. In the alternating “on-wind” l- h step, the checkers are cooled by the passage of cold air through the stove. At any given time, three stoves are simultaneously on gas, while a single stove is on wind.
After 3 h on gas, an on-wind step is initiated. At the start, about one-half of the air, entering at 93°C (2WF), passes through the checkers, the other half being bypassed around the stove through the cold-blast mixer valve. The gas passing through the stove exhausts initially at 1093OC (2000°F). Mixing this with the unheated air pro- duces a blast temperature of 538OC (lOOO°F). The temperature of the heated air from the stove falls rapidly, minute by minute, throughout the on-wind step. The fraction of total air volume bypassed through the mixer valve is continually decreased by pro- gressive closing of this valve, its operation being automatically reg- ulated under control of a thermocouple and potentiometer. At the end of 60 min of on-wind operation, in usual practice the cold-blast mixer valve is practically closed, the entire blast then passing through the checkers.
Satisfactory approach to uniform blast temperature can readily be realized by this automatic control of the mixer valve, provided that the uniform blast temperature does not greatly exceed one-half of the combustion temperature in the preceding on-gas step. The rapid decrease in temperature exhibited by the air discharging from the checkers is a characteristic feature of classical checkerwork heat transfer. The thickness of the refractory flue walls retards the flow of heat by thermal diffusion into the central portions of the brick. Although the heat removed in an on-wind step is less than 5 percent of the total sensible heat stored in the stove refractories, the intro duction and removal of heat from such large-dimensioned refractory elements is sluggish, with the result that the in-and-out movement of heat is largely a skin effect confined closely to the refractory surface.
Open-Hearth and Glass-Tank Regenerators Because of the higher working temperatures, more drastic thermal shock, and dir- tier gases encountered in open-hearth and glass-tank regenerators, checkerwork construction in these furnace units, while somewhat similar to that employed in blast-furnace stoves, requires considera- ble modification. The vertical height of the flues is limited by the elevation of the furnace above plant level. Short flues from 3 to 4.9 m (10 to 16 ft) are common in contrast to the 26- to 29-m (85- to 95- ft) flue lengths in blast-furnace stoves. Larger brick shapes (Fig. 9- IO2b) form flue cross sections 5 times as large as the stove flues, and the percentage of voids in the checkerwork is 51 percent, in contrast with the stove 32 percent voids. In a typical open hearth (Fig. g-104), a checker volume of 210 ms (7500 ft ) contains 810 flues.
As a result of the larger dimensions of flues and the restricted sur- face per unit gas passed, regenerators employed with this type of reverberatory furnace exhibit much lower efficiency than would be realised with smaller flue dimensions. In view, however, of the large amount of iron oxide contained in the open-hearth exhaust gas and the alkali fume present in glass-tank stack gases, resort to smaller checker dimensions has appeared impractical.
Coke-Oven Regenerators In the by-product coke oven, waste- heat recovery is effected in the standard Siemens manner, although, as seen in Fig. 9-105, the dimensions of the upstream and down-
HEAT REGENERATlON 9-9 1
FIG. 9-104 Cross section of an open-hearth steel furnace, including regenerators.
stream regenerators show little outward resemblance either to the blast-furnace stove or to the reverberatory-furnace regenerators. From structural necessity, the coke-oven regenerator is located under the oven itself and must assume the dimensions of an extremely nar- row parallelepiped. Fortunately, the design problem is simplified because of the absence of fume and dust in the flue system. Special regenerator blocks are commonly employed, a typical design being shown in Fig. 9-102c. An oven 12 by 3.7 by 0.5 m (40 ft by 12 ft by 16 in) carbonizing 24 tons/day coal to produce 17 tons/day coke will be provided with a pair of regenerators having a horizontal cross sec- tion of 6.5 m* (70 ft*) containing 210 flues (“slots”) and an overall volume of 8.4 ma (300 fts). Because fuels used in underfiring are either cleaned coke-oven gas, clean blast-furnace gas, or mixtures of the two, difficulty with dirt and fume accumulation in the tlues is not encountered, and because of the lower working temperatures in cok- ing, this intricate type of flue has been found satisfactory. Attempts to duplicate coke-oven-regenerator construction in other Siemens units have not been successful.
Pebble Stove Although considerable ingenuity has been applied to the design of the Cowper checkerwork, involving variations in
FIG. 9-105 Regenerator system for by-product coke ovens
FIG. 9-106 Pebble-bed regenerator.
bricklaying patterns and special ceramic shapes, the checkerbrick regenerators still exhibit five engineering defects: (1) high initial cost of construction; (2) unsatisfactory thermal efficiency with clean heat- exchanging surfaces; (3) tendency to lose efficiency with dust-and fume-coated surfaces inevitable with dirty gas; (4) inaccessibility of surface causing lost time and high labor cost in any cleaning opera- tion; and (5) danger of fusion, slagging, and spalling when subjected to high maximum temperatures and rapid temperature changes. It is possible that one or even all of these difficulties are inherent in the Cowper checkerbrick system, as such. No serious attempt, however, to alter US construction appears to have been made prior to 1929, when the Department of Agriculture undertook to substitute the so- called pebble-bed heat-exchanging structure for the classical check- erwork in order to provide higher air preheat in the blast-furnace smelting of phosphate rock.
In this departure from regenerator precedent, a mass of small refractory particles, enclosed in a brick-lined steel shell, was substi- tuted as a functional equivalent of standard checkerwork (see Fig. 9- 106). In the operation of an experimental phosphate blast furnace, blast temperatures as high as 1093OC (2000°F) were readily obtained. In later operation of a 25ton/day blast furnace producing pig iron, ferromanganese, ferrochromium, and ferrosilicon, air pre- heat temperatures of 1538OC (2800°F) were attained and main- tained. In connection with the process of converting air into NO [Daniels and Gilbert, hd. Eng. Gem., 40, 1719 (1948)] air was pre heated to 1980°C (36OOOF) in magnesia refractory pebble stoves.
Aside from the engineering value of the elevated temperatures attained with pebble-stove regenerators, extremely high thermal effi- ciencies are an inherent characteristic of this type of heat interchanger.
Ljungstrom Heater The continuous-regenerative type of air heater or recuperator is familiarly known as the Ljungstrom heater (Fig. g-107). The heater assembly consists of a slow-moving rotor packed with closely spaced metal plates or wires. At each end of the rotor is a housing divided by partitions to confine the hot gas to one half of the rotor and the cold gas to the other. Radial and circum- ferential seals sliding on the rotor limit the leakage between streams. The rotor is divided into sectors and each sector packed with a filling to promote high heat transfer at low pressure drop. The packing may be divided into layers of different materials to suit the temperature and corrosion conditions.
Leakage between streams comes from (1) entrainment in the rotor passages (this can be reduced by providing for a blowout section between the hot and cold zones), (2) leakage around the circumfer- ence of the rotor through the annular space between rotor shell and housing, and (3) leakage of radial seals.
These heaters are available with rotors up to 6-m (29ft) diameter. Gas temperatures up to 816OC (15OO’F) can be handled [a higher temperature of 982OC (18OW’F) with special alloys]. and gas face velocities are usually around 2.5 m/s (500 ft/min). Thickness of rotor depends on service, efficiency, and operating conditions but usually
9-92 ENERGY UTIUZATION, CONVERSION, AND RESOURCE CONSERVATION
FIG. 9-107 Ljungstrom air heater
ranges from 20.3 to 91.4 cm (8 to 36 in). Rotors are driven by small motors with rotor speed up to 10 to 20 r/min. The effectiveness of these heaters can be as high as 85 to QO percent.
Ljungstrom-type heaters are widely used in power-plant boilers. Use in process industries is increasing for air conditioning and build- ing heating by transferring heat between the fresh and exhaust air streams and for process-heat recovery.
Rotor kontalnlng heat transfer surface)
Miscellaneous Systems Many systems have been proposed for transferring heat regeneratively, such as described earlier, plus the use of high-temperature liquids and tluidized beds for direct contact with gases, but other problems which limit industrial application are encountered. These systems are covered by methods described in Sec. 11.
![Energy Conservation in Road Pavement Design, Maintenance ......EIE/06/039/SI2.448265 ECRPD [Type text] Energy Conservation in Road Pavement Design, Maintenance and Utilisation ECRPD](https://static.documents.pub/doc/80x56/613170e01ecc51586944bcae/energy-conservation-in-road-pavement-design-maintenance-eie06039si2448265.jpg)
