05.section ii_steam, its generation & use, 41_ed

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Steam 41

Section II

Steam Generation from

Chemical Energy

This section containing 17 chapters applies the fundamentals of steam gen-eration to the design of boilers, superheaters, economizers and air heaters forsteam generation from chemical or fossil fuels (coal, oil and natural gas). As

discussed in Chapter 1, the fuel and method of combustion have a dramaticimpact on the size and configuration of the steam producing system. There-fore, Chapters 9 and 10 begin the section by exploring the variety and charac-teristics of chemical and fossil fuels, and summarize the combustion calcula-tions that are the basis for system design.

The variety of combustion systems available to handle these fuels and thesupporting fuel handling and preparation equipment are then described inChapters 11 through 18. These range from the venerable stoker in its newestconfigurations to circular burners used for pulverized coal, oil and gas, to flu-idized-bed combustion and coal gasification. A key element in all of these sys-tems is the control of atmospheric emissions, in particular oxides of nitrogen(NOx) which are byproducts of the combustion process. Combustion NOx con-trol is discussed as an integral part of each system. It is also discussed in Sec-tion IV, Chapter 34.

Based upon these combustion systems, Chapters 19 through 22 address thedesign and performance evaluation of the major steam generator heat trans-fer components: boiler, superheater, reheater, economizer and air heater. Theseare configured around the combustion system selected with special attentionto properly handling the high temperature, often particle-laden flue gas. Thefundamentals of heat transfer, fluid dynamics, materials science and struc-tural analysis are combined to provide the tradeoffs necessary for an economi-cal steam generating system design. The boiler setting and auxiliary equip-ment, such as sootblowers, ash handling systems and fans, which are key ele-ments in completing the overall steam system, conclude this section in Chap-ters 23 through 25.


2/334Steam 41 / Sources of Chemical Energy 9-1


Chapter 9

Sources of Chemical Energy

World energy consumption continues to grow withthe primary resources being the fossil fuels. Between1991 and 2000, world production of primary energy

increased at an annual rate of 1.4%. Production of pri-mary energy increased from 351 1015 Btu (370 1018

J) in 1991 to 397 1015 Btu (419 1018 J) in 2000.The trend in energy production by source from 1970to 2000 is shown in Fig. 1. World energy production andfossil fuel reserves by region are shown in Figs. 2 and 3.

The United States (U.S.), former Soviet Union(FSU) and China were the leading producers and con-sumers of world energy in 2000. They produced 38%and consumed 41% of the worlds energy. Energy usein the developing world is expected to continue to in-crease with demand in developing Asia and Centraland South America more than doubling between 1999and 2020. Projected world energy consumption

through the year 2025 is shown in Fig. 4.Annual energy production in the U.S. rose to 71.6

1015 Btu (75.5 1018 J) in 2000, which is about 18%of world production. Approximately 81% of this energyis in the form of fossil fuels. U.S. energy productionby source is given in Fig. 5.

The relative U.S. production of coal compared toother fossil fuels has increased since 1976, when 26%was coal, 29% was crude oil and 33% was natural gas.In 1999, coal production accounted for 32%, crude oilwas 17% and natural gas was 28%. Coal production

for 1999 and 2000 represented the first time in fortyyears that production declined for two consecutiveyears. On an annual basis, the average utility priceper ton of coal delivered to utilities dropped by 1.8% in2000, continuing a downward trend started in 1978.

Overall energy consumption in the U.S. was ap-proximately 99 1015 Btu (104 1018 J) in 2000. About28% of this energy was consumed by electric utilities

in the form of fossil fuels.Overall U.S. fossil fuel consumption continues toincrease and grew to 84 1015 Btu (88.6 1018 J) in2000. In spite of the decline in the cost of crude oil inthe 1980s, it continues to be the most dominant andcostly fuel in the fossil fuel mix. The trends in coal, oiland natural gas prices are given in Fig. 6.

World availability of coal

Coal is the second leading source of fuel, supplying23% of the worlds primary energy in 2000. It is also themost used fossil fuel for utility and industrial power gen-

QuadrillionBtu

180

160

140

120

100

80

60

40

20

0Crude Oiland NGL

NaturalGas (Dry)

Coal HydroelectricPower

NuclearPower

101

133136

37

55

76

63 7

3

94

12 1

8 23

1 820

1970

1980

1990

2000

155

91 9

3

28

26

Fig. 1 Trends in world energy production by source (NGL = naturalgas liquids).

Eastern Europe and FSU16%

Far East andOceania

21%

North America25%WesternEurope

11%

Central/South America6%

Middle East14%

Africa7%

Fig. 2 World primary energy production by region, 2001.


3/3349-2 Steam 41 / Sources of Chemical Energy


eration. Major reserves by coal type and location are lig-nite in the U.S. and the former Soviet Union (FSU); sub-bituminous in China, the FSU, Australia and Germany;and bituminous in China, the U.S. and the FSU.

Reserves of coal by regions of the world are givenin Fig. 3. Of those regions, China consumed the most(25%) in 2000, followed by the U.S. (21%) and the FSU(9%). Because of its worldwide availability and lowprice, the demand for coal has grown and world coal

trade has expanded by about 40% since 1980. Thelargest coal exporters are Australia, China, Indonesia,South Africa, the U.S., Canada, the FSU and Poland.1

U.S. availability of coal

The coal reserves of the U.S. constitute a vast en-ergy resource, accounting for about 25% of the worldstotal recoverable coal.2According to the Energy Infor-mation Administration (EIA), the national estimate ofthe Demonstrated Reserve Base coal resources remain-ing as of 2002, is 498 billion short tons. Reserves thatare likely to be mined are estimated at 275 109 t (249

109 tm ).3 The U.S. produced 1.074 109 t (0.974 109 tm) of coal in 2000. Fig. 7 summarizes U.S. production from 1978 to 2000. U.S. coal consumption hassteadily increased from 0.7 billion short tons in 1980

to 1.05 billion in 1999. The states with the largest coalreserves in the ground as of January, 2000, are shownin Table 1.4 States with large reserves, such as Montana and Illinois, do not necessarily rank as high in production as Wyoming, Kentucky or West Virginia.

Because of the resulting sulfur dioxide (SO2) emissions, coal sulfur levels are important production criteria and have been a factor in the growth of production from the western region, particularly the PowderRiver Basin. Table 2 shows the distribution of coareserves by state at various sulfur levels.

Coal fields in the U.S. are shown in Fig. 8. The twolargest producing regions are the western region consisting of Arizona, Colorado, Montana, New MexicoNorth Dakota, Utah, Washington, and Wyoming andthe Appalachian region including Pennsylvania, West

Virginia, Ohio, western Maryland, eastern KentuckyVirginia, Tennessee and Alabama. In 2000, these regions produced 510.7 106 t (463 106 tm ) and 419 106 t (380 106 tm ), respectively. Two-thirds of the re

Crude OilEnd of Year 1999

1018 Billion Barrels

WesternEurope

MiddleEast

Far East and Oceania

Africa

Eastern Europeand FSU

North, Southand

CentralAmerica

Natural GasEnd of Year 1999

5150 Trillion ft

MiddleEast

Africa

Far East and Oceania

EasternEurope

and FSUWestern Europe

North, South and Central America

CoalEnd of Year 1999

1082 Billion Short Tons

EasternEurope

and FSU

Middle East, Far Eastand Oceania

Africa

WesternEurope

North, South and Central America

Fig. 3 Fossil fuel reserves by world region.

Fig. 5 U.S. energy production by source, 2002.

Crude Oil17%

Coa31%

Natural Gas28%

Wood, Waste, Other5%

HydroelectricPower

4%

Nuclear Power11%

Natural GasPlant Liquids

4%

Fig. 4 World primary energy consumption by fuel.1

Q

uadrillionBtu

250

200

150

100

50

02025

Year

20102000199019801970

History Projections

Oil

Natural Gas

Coal

Renewables

Nuclear




serves lie in the Great Plains, the Rocky Mountainsand the western states. These coals are mostly subbi-tuminous and lignitic, which have low sulfur content.Therefore, these fields have been rapidly developedto meet the increasing demands of electric utilities.The low sulfur coal permits more economical conform-ance to the Federal Clean Air Act, its Amendments, andacid rain legislation. (See Chapter 32.)

U.S. electric utilities used coal to generate 51% ofthe net electrical power in 2000, and remain the larg-est coal consumers. Continuing the downward trendsince 1982, the average delivered cost of coal decreased27% in current dollars per million Btu.

Environmental concerns about SO2, nitrogen oxides(NOx), carbon dioxide (CO2) and mercury (Hg) emis-sions could limit the growth of coal consumption. How-ever, the U.S., as well as Japan and several Europeancountries, is researching clean coal technologies toreduce these emissions while boosting power produc-tion efficiency. These technologies are rapidly ap-proaching commercialization in the U.S. They areexpected to be integrated into current and future

power plants.

How coal is formed

Coal is formed from plants by chemical and geologi-cal processes that occur over millions of years. Layersof plant debris are deposited in wet or swampy regionsunder conditions that prevent exposure to air and com-plete decay as the debris accumulates. Bacterial ac-tion, pressure and temperature act on the organicmatter over time to form coal. The geochemical pro-cess that transforms plant debris to coal is called coali-fication. The first product of this process, peat, oftencontains partially decomposed stems, twigs, and bark

Table 2

Sulfur Content and Demonstrated Total Underground and

Surface Coal Reserve Base of the U.S. (Million tons)

Sulfur Range, %State 3.0 Unknown Total*

Alabama 624.7 1,099.9 16.4 1,239.4 2,981.8Alaska 11,458.4 184.2 0.0 0.0 11,645.4Arizona 173.3 176.7 0.0 0.0 350.0

Arkansas 81.2 463.1 46.3 74.3 665.7Colorado 7,475.5 786.2 47.3 6,547.3 14,869.2Georgia 0.3 0.0 0.0 0.2 0.5Illinois 1,095.1 7,341.4 42,968.9 14,256.2 65,664.8Indiana 548.8 3,305.8 5,262.4 1,504.1 10,622.6Iowa 1.5 226.7 2,105.9 549.2 2,884.9Kansas 0.0 309.2 695.6 383.2 1,388.1Kentucky-East 6,558.4 3,321.8 299.5 2,729.3 12,916.7Kentucky-West 0.2 564.4 9,243.9 2,815.9 12,623.9Maryland 135.1 690.5 187.4 34.6 1,048.2Michigan 4.6 85.4 20.9 7.0 118.2Missouri 0.0 182.0 5,226.0 4,080.5 9,487.3Montana 101,646.6 4,115.0 502.6 2,116.7 108,396.2New Mexico 3,575.3 793.4 0.9 27.5 4,394.8North Carolina 0.0 0.0 0.0 31.7 31.7North Dakota 5,389.0 10,325.4 268.7 15.0 16,003.0Ohio 134.4 6,440.9 12,534.3 1,872.0 21,077.2Oklahoma 275.0 326.6 241.4 450.5 1,294.2Oregon 1.5 0.3 0.0 0.0 1.8Pennsylvania 7,318.3 16,913.6 3,799.6 2,954.2 31,000.6South Dakota 103.1 287.9 35.9 1.0 428.0Tennessee 204.8 533.2 156.6 88.0 986.7Texas 659.8 1,884.6 284.1 444.0 3,271.9Utah 1,968.5 1,546.7 49.4 478.3 4,042.5Virginia 2,140.1 1,163.5 14.1 330.0 3,649.9Washington 603.5 1,265.5 39.0 45.1 1,954.0West Virginia 14,092.1 14,006.2 6,823.3 4,652.5 39,589.8Wyoming 33,912.3 14,657.4 1,701.1 3,060.3 53,336.1Total* 200,181.4 92,997.5 92,571.5 50,788.0 436,725.7

*Data may not add to totals shown due to independent rounding.Source, Bureau of Mines Bulletin, CoalBituminous and Lignite,1974.

Table 1

U.S. Energy Information Administration States with

Largest Demonstrated Coal Reserves (x 109 t)*

Total Underground Surface % TotalState Reserves Reserves Reserves U.S.

t (tm) t (tm) t (tm)

Montana 120 109 71 64 49 44 23.9Illinois 105 95 88 80 17 15 20.9Wyoming 67 61 43 39 24 22 13.3West Virginia 35 32 30 27 4 3.6 7.0Kentucky 31 28 18 16 14 13 6.2Pennsylvania 28 25 24 22 4 3.6 5.5Ohio 24 22 18 16 6 5 4.8Colorado 17 15 12 11 5 4.5 3.4Texas 13 12 0 0 13 11.8 2.6New Mexico 12 11 6 5 6 5 2.4Indiana 10 9 9 8 1 0.9 2.0All others 41 37 20 18 21 19 8.2Total U.S. 503 456 339 306 164 147 100.0

* Figures are rounded and include anthracite.

Chain

ed(1996)DollarsperMillionBtu 10

8

6

4

2

02000

Year

19951990198519801975

Crude Oil

Natural Gas

Coal

Fossil FuelComposite

Fig. 6 Trends in U.S. fossil fuel prices.

MillionShortTons

700

600

500

400

300

200

100

0

1978

1989

2000

Bituminous Coal Subbituminous Coal Lignite

657

534 549

434

231

9734

87 89

Fig. 7 U.S. coal production trends.




and is not classified as coal. However, peat is progres-sively transformed to lignite that eventually can be-come anthracite, given the proper progression of geo-logical changes.

Various physical and chemical processes occur dur-ing coalification. The heat and pressure to which theorganic material is exposed cause chemical and struc-tural changes. These changes include an increase incarbon content; loss of water, oxygen and hydrogen;and resistance to solvents. The coalification process isshown schematically in Fig. 9.

Coal is very heterogeneous and can vary in chemi-cal composition by location. In addition to the majororganic ingredients (carbon, hydrogen and oxygen),coal also contains impurities. The impurities that areof major concern are ash and sulfur. The ash resultsfrom mineral or inorganic material introduced duringcoalification. Ash sources include inorganic sub-

stances, such as silica, that are part of the chemicalstructure of the plants. Dissolved inorganic ions andmineral grains found in swampy water are also cap-tured by the organic matter during early coalification.Mud, shale and pyrite are deposited in pores and cracksof the coal seams.

Sulfur occurs in coal in three forms: 1) organic sul-fur, which is part of the coals molecular structure, 2)pyritic sulfur, which occurs as the mineral pyrite, and3) sulfate sulfur, primarily from iron sulfate. The prin-cipal sulfur source is sulfate ion, found in water. Freshwater has a low sulfate concentration while salt wa-ter has a high sulfate content. Therefore, bituminous

coal, deposited in the interior of the U.S. when seascovered this region, are high in sulfur. Some Iowacoals contain as much as 8% sulfur.

Although coal is a complex, heterogeneous mixture

and not a polymer or biological molecule, it is sometimes useful for chemists to draw an idealized struc-tural formula. These formulas can serve as models thatillustrate coal reactions. This can aid the further development of coal processes such as gasification, com-bustion and liquefaction.

Fig. 9 The coalification process (DAF = dry ash-free).

Fig. 8 U.S. coal reserves.




Classifying coal

A coal classification system is needed because coalis a heterogeneous substance with a wide range of com-position and properties. Coals are typically classifiedby rank. This indicates the progressive alteration inthe coalification process from lignite to subbituminous,bituminous and anthracite coals. The rank indicatesa coals geological history and broad characteristics.

ASTM classification by rankThe system used in the U.S. for classifying coal by rank

was established by the American Society for Testing andMaterials (ASTM).5ASTM classification is a system thatuses the volatile matter (VM) and fixed carbon (FC) re-sults from the proximate analysis and the heating valueof the coal as ranking criteria. This system aids in iden-tifying commercial uses of coals and provides basic in-formation regarding combustion characteristics.

The classification system is given in Table 3 anddescribed in section D 388 of the ASTM standards.Proximate analysis is based on the laboratory proce-dure described in ASTM D 3172. In this procedure,

moisture content, ash remaining after complete burn-ing, amount of gases released when heated to a pre-scribed temperature, and fixed carbon remaining af-ter volatilization are determined.

Table 4 gives a typical as-received proximate analy-sis of a West Virginia coal. An as-received analysis in-cludes the total moisture content of the coal as it isreceived at the power plant.

For older or higher rank coals, FC and VM are used

as the classifying criteria. These criteria are determinedon a dry, mineral-matter-free basis using formulas de-veloped by S.W. Parr in 1906 (shown in Equations 1through 6).6 The younger or low rank coals are classi-fied by Btu content on a moist, mineral-matter-free ba-sis. Agglomerating or weathering indices, as described in

ASTM D 388, are used to differentiate adjacent groups.

Parr Formulas

Dry, mineral-free

S

S

FC

FC

M A

=

+ +( )

0 15

100 1 08 0 55100

.

. ., % (1)

Table 3Classification of Coals by Ranka (ASTM D 388)

Fixed Carbon Volatile Matter Calorific ValueLimits, % Limits, % Limits, Btu/lb

(Dry, Mineral- (Dry, Mineral- (Moist,b

Matter-Free Matter-Free Mineral-Matter-Basis) Basis) Free Basis)

Equal or Equal Equal orGreater Less Greater or Less Greater Less Agglomerating

Class Group Than Than Than Than Than Than Character

1. Meta-anthracite 98 2 I. Anthracitic 2. Anthracite 92 98 2 8 Nonagglomerating

3. Semianthracitec 86 92 8 14

1. Low volatile bituminous coal 78 86 14 22 2. Medium volatile bituminous coal 69 78 22 31

II. Bituminous 3. High volatile A bituminous coal 69 31 14,000d Commonly

4. High volatile B bituminous coal 13,000d 14,000 agglomeratinge

5. High volatile C bituminous coal 11,500 13,00010,500e 11,500 Agglomerating

1. Subbituminous A coal 10,500 11,500III. Subbituminous 2. Subbituminous B coal 9,500 10,500

3. Subbituminous C coal 8,300 9,500 Nonagglomerating

1. Lignite A

6,300 8,300

IV. Lignitic

2. Lignite B 6,300

a This classification does not include a few coals, principallynonbanded varieties, which have unusual physical and chemicalproperties and which come within the limits of fixed carbonor calorific value of the high volatile bituminous andsubbituminous ranks. All of these coals either contain lessthan 48% dry, mineral-matter-free fixed carbon or have morethan 15,500 moist, mineral-matter-free Btu/lb.b Moist refers to coal containing its natural inherent moisturebut not including visible water on the surface of the coal.

c If agglomerating, classify in low volatile group of thebituminous class.d Coals having 69% or more fixed carbon on the dry, mineral-matter-free basis shall be classified according to fixed carbon,regardless of calorific value.e It is recognized that there may be nonagglomerating varietiesin these groups of the bituminous class, and there are notableexceptions in high volatile C bituminous group.




Dry, mineral-free

Dry, mineral-free

VM

FC

=

100 , %(2)

Moist, mineral-free Btu

Btu S

S, per l

=

+( )

50

100 1 08 0 55100

. .Abb (3)

Approximation Formulas

Dry, mineral-free

S

FC

FC

M A

=

+ +( )

100 1 1 0 1100

. ., % (4)

Dry, mineral-free

Dry, mineral-free

VM

FC

=

100 , %(5)

Moist, mineral-free Btu

Btu

S, per lb

=

+( )

100 1 1 0 1100

. .A(6)

where

Btu = heating value per lb (kJ/kg = 2.326 Btu/lb)FC = fixed carbon, %VM = volatile matter, %M = bed moisture,

A = ash, %

S = sulfur, %all for coal on a moist basis.

Table 5 lists 16 selected U.S. coals, arranged in orderof ASTM classification. The following descriptions brieflysummarize the characteristics of each coal rank.

Peat Peat, the first product in the formation of coal,is a heterogeneous material consisting of partially de-composed plant and mineral matter. Its color rangesfrom yellow to brownish-black, depending on its geo-logic age. Peat has a moisture content up to 70% anda heating value as low as 3000 Btu/lb (6978 kJ/kg).

Lignite Lignite is the lowest rank coal. Lignites are

relatively soft and brown to black in color with heat-ing values of less than 8300 Btu/lb (19,306 kJ/kg). Thedeposits are geologically young and can contain recognizable remains of plant debris. The moisture content of lignites is as high as 30% but the volatile content is also high; consequently, they ignite easily. Lignite coal dries when exposed to air and spontaneouscombustion during storage is a concern. Long distanceshipment of these coals is usually not economical be

cause of their high moisture and low Btu content. Thelargest lignite deposit in the world spreads over theregions of North and South Dakota, Wyoming, andMontana in the U.S. and parts of Saskatchewan andManitoba in Canada.

Subbituminous Subbituminous coals are blackhaving little of the plant-like texture and none of thebrown color associated with the lower rank lignitecoal. Subbituminous coals are non-coking (undergolittle swelling upon heating) and have a relatively highmoisture content which averages from 15 to 30%. Theyalso display a tendency toward spontaneous combustion when drying.

Although they are high in VM content and ignite

easily, subbituminous coals generally have less ashand are cleaner burning than lignite coals. Subbitu-minous coals in the U.S. in general have a very lowsulfur content, often less than 1%. Because they havereasonably high heating values [8300 to 11,500 Btulb (19,306 to 26,749 kJ/kg)] and low sulfur contentswitching to subbituminous coal has become an attrac-tive option for many power plants to limit SO2 emissions

Bituminous Bituminous coal is the rank most commonly burned in electric utility boilers. In general, itappears black with banded layers of glossy and dullblack. Typical bituminous coals have heating valuesof 10,500 to 14,000 Btu/lb (24,423 to 32,564 kJ/kg)and a fixed carbon content of 69 to 86%. The heatingvalue is higher, but moisture and volatile content arelower than the subbituminous and lignite coals. Bi-tuminous coals rarely experience spontaneous com-bustion in storage. Furthermore, the high heatingvalue and fairly high volatile content enable bituminous coals to burn easily when pulverized to a finepowder. Some types of bituminous coal, when heatedin the absence of air, soften and release volatiles toform the porous, hard, black product known as cokeCoke is used as fuel in blast furnaces to make iron.

Anthracite Anthracite, the highest rank of coal, isshiny black, hard and brittle, with little appearanceof layers. It has the highest content of fixed carbon86 to 98%. However, its low volatile content makes ita slow burning fuel. Most anthracites have a very lowmoisture content of about 3%; heating values of15,000 Btu/lb (34,890 kJ/kg) are slightly lower thanthe best quality bituminous coals. Anthracite is low insulfur and volatiles and burns with a hot, clean flameThese qualities make it a premium fuel used mostlyfor domestic heating.

Other classification systems

There are other classifications of coal that are currently in limited use in Europe. These are the International Classification of Hard Coals by Type and the

Table 4Coal Analyses on As-Received Basis(Pittsburgh Seam Coal, West Virginia)

Proximate Analysis Ultimate AnalysisComponent % by wt Component % by wt

Moisture 2.5 Moisture 2.5Volatile matter 37.6 Carbon 75.0

Fixed carbon 52.9 Hydrogen 5.0Ash 7.0 Sulfur 2.3Total 100.0 Nitrogen 1.5

Oxygen 6.7Heating value, Ash 7.0

Btu/lb 13,000 Total 100.0(kJ/kg) (30,238)




International Classification of Brown Coals. These sys-tems were developed by the Coal Committee of theEconomic Commission for Europe in 1949.

Coal characterization

As previously described, the criteria for ranking coalare based on its proximate analysis. In addition to pro-viding classifications, coal analysis provides other use-ful information. This includes assistance in selectingcoal for steam generation, evaluation of existing han-dling and combustion equipment, and input for de-sign. The analyses consist of standard ASTM proce-dures and special tests developed by The Babcock &Wilcox Company (B&W). The following briefly sum-marizes some of these tests.

Standard ASTM analyses5,7

Bases for analyses Because of the variability ofmoisture and ash content in coals, the compositiondetermined by proximate analysis can be reported onseveral bases. The most common include as-received,moisture-free or dry, and mineral-matter-free. The as-received analysis reports the percentage by weight ofeach constituent in the coal as it is received at the labo-ratory. As-received samples contain varying levels ofmoisture. For analysis on a dry basis, the moisture ofthe sample is determined and then used to correct each

constituent to a common dry level. As previously men-tioned, the ash in coal as determined by proximateanalysis is different than the mineral matter in coal.This can cause problems when ranking coals by the

ASTM method. Formulas used to correct for the min-eral matter and to determine volatile matter, fixedcarbon and heating value on a mineral-matter-freebasis are provided in Equations 1 to 6 above.

Moisture determination Coal received at an electricpower plant contains varying amounts of moisture inseveral forms. There is inherent and surface moisturein coal. Inherent moisture is that which is a naturallycombined part of the coal deposit. It is held tightlywithin the coal structure and can not be removed eas-ily when the coal is dried in air. The surface moistureis not part of the coal deposit and has been added ex-ternally. Surface moisture is more easily removed fromcoal when exposed to air. It is not possible to distin-guish, by analysis, inherent and surface moisture.

There are many other moistures that arise whencharacterizing coal including equilibrium, free and airdry moisture. Their definitions and use depend on theapplication. Equilibrium moisture is sometimes usedas an estimate of bed moisture. The ASTM standardterminology of coal and coke, D 121, defines the totalcoal moisture as the loss in weight of a sample undercontrolled conditions of temperature, time and air flow.Using ASTM D 3302, the total moisture is calculated

Table 5Sixteen Selected U.S. Coals Arranged in Order of ASTM Classification

Coal Rank Coal Analysis, Bed Moisture Basis Rank Rank

No. Class Group State County M VM FC A S Btu FC Btu

1 I 1 Pa. Schuylkill 4.5 1.7 84.1 9.7 0.77 12,745 99.2 14,2802 I 2 Pa. Lackawanna 2.5 6.2 79.4 11.9 0.60 12,925 94.1 14,8803 I 3 Va. Montgomery 2.0 10.6 67.2 20.2 0.62 11,925 88.7 15,340

4 II 1 W.Va. McDowell 1.0 16.6 77.3 5.1 0.74 14,715 82.8 15,6005 II 1 Pa. Cambria 1.3 17.5 70.9 10.3 1.68 13,800 81.3 15,5956 II 2 Pa. Somerset 1.5 20.8 67.5 10.2 1.68 13,720 77.5 15,4857 II 2 Pa. Indiana 1.5 23.4 64.9 10.2 2.20 13,800 74.5 15,5808 II 3 Pa. Westmoreland 1.5 30.7 56.6 11.2 1.82 13,325 65.8 15,2309 II 3 Ky. Pike 2.5 36.7 57.5 3.3 0.70 14,480 61.3 15,040

10 II 3 Ohio Belmont 3.6 40.0 47.3 9.1 4.00 12,850 55.4 14,380

11 II 4 Ill. Williamson 5.8 36.2 46.3 11.7 2.70 11,910 57.3 13,71012 II 4 Utah Emery 5.2 38.2 50.2 6.4 0.90 12,600 57.3 13,56013 II 5 Ill. Vermilion 12.2 38.8 40.0 9.0 3.20 11,340 51.8 12,630

14 III 2 Wyo. Sheridan 25.0 30.5 40.8 3.7 0.30 9,345 57.5 9,74515 III 3 Wyo. Campbell 31.0 31.4 32.8 4.8 0.55 8,320 51.5 8,790

16 IV 1 N.D. Mercer 37.0 26.6 32.2 4.2 0.40 7,255 55.2 7,610

Notes: For definition of Rank Classification according to ASTM requirements, see Table 3.

Data on Coal (Bed Moisture Basis)

M = equilibrium moisture, %; VM = volatile matter, %; Rank FC = dry, mineral-matter-free fixed carbon, %;FC = fixed carbon, %; A = ash, %; S = sulfur, %; Rank Btu = moist, mineral-matter-free Btu/lb.Btu = Btu/lb, higher heating value. Calculations by Parr formulas.




from the moisture lost or gained in air drying and theresidual moisture. The residual moisture is determinedby oven drying the air dried sample. Because subse-quent ASTM analyses (such as proximate and ulti-mate) are performed on an air dried sample, the re-sidual moisture value is required to convert these re-sults to a dry basis. In addition, the moisture lost onair drying provides an indication of the drying re-quired in the handling and pulverization portions of

the boiler coal feed system.Proximate analysisProximate analysis, ASTM D 3172,

includes the determination of volatile matter, fixed car-bon and ash. Volatile matter and fixed carbon, exclusiveof the ash, are two indicators of coal rank. The amountof volatile matter in a coal indicates ease of ignition andwhether supplemental flame stabilizing fuel is required.The ash content indicates the load under which the ashcollection system must operate. It also permits assessingrelated shipping and handling costs.

Ultimate analysis Ultimate analysis, described inASTM D 3176, includes measurements of carbon, hy-drogen, nitrogen and sulfur content, and the calcula-tion of oxygen content. Used with the heating valueof the coal, combustion calculations can be performedto determine coal feed rates, combustion air require-ments, heat release rates, boiler performance, andsulfur emissions from the power plant. (See Table 4.)

Heating value The gross calorific value of coal, de-termined using an adiabatic bomb calorimeter as de-scribed in ASTM D 2015, is expressed in Btu/lb (kJ/kg) on various bases (dry, moisture and ash free, etc.).

This value determines the maximum theoretical fuelenergy available for the production of steam. Conse-quently, it is used to determine the quantity of fuelwhich must be handled, pulverized and fired.

Gross (higher) heating value (HHV) is defined as

the heat released from combustion of a unit fuel quan-tity (mass), with the products in the form of ash, gas-eous CO2, SO2, nitrogen and liquid water, exclusive ofany water added as vapor. The net (lower) heatingvalue (LHV) is calculated from the HHV. It is the heatproduced by a unit quantity of fuel when all water inthe products remains as vapor. This LHV calculation(ASTM Standard D 407) is made by deducting 1030Btu/lb (2396 kJ/kg) of water derived from the fuel,including the water originally present as moisture andthat formed by combustion. In the U.S., the gross calo-rific value is commonly used in heat balance calcula-tions, while in Europe the net value is generally used.

Grindability The Hardgrove Grindability Test, de-

veloped by B&W, is an empirical measure of the rela-tive ease with which coal can be pulverized. The ASTMD 409 method has been used for the past 30 years toevaluate the grindability of coals. The method involvesgrinding 50 g of air-dried 16 30 mesh (1.18 mm 600m) test coal in a small ball-and-race mill. The millis operated for 60 revolutions and the quantity of ma-terial that passes a 200 mesh (75 micron) screen is mea-sured. From a calibration curve relating 200 mesh(75 micron) material to the grindability of standardsamples supplied by the U.S. Department of Energy,the Hardgrove Grindability Index (HGI) is determinedfor the test coal. Pulverizer manufacturers have de-

veloped correlations relating HGI to pulverizer capacity at desired levels of fineness.

Sulfur forms The sulfur forms test, ASTM D 2492measures the amounts of sulfate sulfur, pyritic sulfurand organically bound sulfur in a coal. This is accomplished by measuring the total sulfur, sulfate, and pyritic sulfur contents and obtaining the organic sulfurby difference. The quantity of pyritic sulfur is an indicator of potential coal abrasiveness.

Free swelling index The free swelling index can beused to indicate caking characteristics. The index isdetermined by ASTM D 720 which consists of heat-ing a one gram coal sample for a specified time andtemperature. The shape of the sample or buttonformed by the swelling coal is then compared to a setof standard buttons. Larger formed buttons indicatehigher free swelling indices. Oxidized coals tend tohave lower indices. The free swelling index can be usedas a relative measurement of a coals caking proper-ties and extent of oxidation.

Ash fusion temperatures Coal ash fusion temperatures are determined from cones of ash prepared and

heated in accordance with ASTM method D 1857. Thetemperatures at which the cones deform to specificshapes are determined in oxidizing and reducing atmospheres. Fusion temperatures provide ash meltingcharacteristics and are used for classifying the slagging potentials of the lignitic-type ashes.

Ash composition Elemental ash analysis is con-ducted using a coal ash sample produced by the ASTMD 3174 procedure. The elements present in the ashare determined and reported as oxides. Silicon dioxide (SiO2), aluminum oxide (Al2O3), titanium dioxide(TiO2), ferric hydroxide (Fe2O3), calcium oxide (CaO)magnesium oxide (MgO), sodium oxide (Na2O) andpotassium oxide (K2O) are measured using atomic

absorption per ASTM D 3682. The results of the ashanalyses permit calculations of fouling and slaggingindices and slag viscosity versus temperature relationships. The nature, composition and properties of coalash and their effects on boiler performance are described further in Chapter 21.

Special B&W tests7

Burning profiles The burning profile technique wasoriginated by B&W for predicting the relative combustion characteristics of fuels. The technique and application of results were described by Wagoner andDuzy,8 and are routinely applied to liquid and solid

fuels. The test uses derivative thermogravimetry inwhich a sample of fuel is oxidized under controlled conditions. A 300 mg sample of solid fuel with a particle sizeless than 60 mesh (250 microns) is heated at 27F/min(15C/min) in a stream of air. Weight change is measuredcontinuously and the burning profile is the resulting plotof rate of weight loss versus furnace temperature.

Coals with similar burning profiles would be ex-pected to behave similarly in large furnaces. By comparing the burning profile of an unknown coal withthat of a known sample, furnace design, residencetime, excess air and burner settings can be predictedIn comparing profiles, key information is provided by




the start and completion temperatures of oxidation.The area under the temperature curve is proportionalto the amount of combustible material in the sample;the height of the curve is a measure of the combus-tion intensity. Burning profiles are particularly use-ful for preliminary evaluations of new boiler fuels suchas chars, coal-derived fuels and processed refuse. Fig.10 shows burning profiles of coals of various ranks.

Abrasiveness indexThe abrasiveness of coal affects

pulverizer grinding element life, and quartz particlesin the coal can significantly contribute to its abrasive-ness. A procedure for determining a coals quartz counthas been developed at B&W. This procedure consistsof burning the coal, collecting and washing the ashto remove acid soluble constituents, and screening toseparate size fractions. In each size fraction, 1000 par-ticles are counted and the number of quartz particlesis determined by a microscopic technique. From thesedata, the relative quartz value, an indicator of the coalsrelative abrasiveness, is calculated.

Another abrasion index is determined using theYancey-Geer Price apparatus. In this test, a sample ofcoal, sized 0.25 in. 0 (6.35 mm 0), is placed in contactwith four metal test samples or coupons attached to arotating shaft. The shaft is rotated at 1440 rpm (150.8rad/s) for a total of 12,000 revolutions (75,400 rad). Theweight loss of the metal coupons is then determined, fromwhich a relative abrasion index is calculated. Indicesfrom the test coals can be compared to those for otherfuels. B&W has used the Yancey-Geer Price Index todetermine wear in full scale pulverizers. The quartzcount procedure and the Yancey-Geer Price procedurescan provide some relative information and insight whencomparing the abrasiveness of different coals; however,they have limited value in predicting actual field wearrates. (See Chapter 13.)

Erosiveness index Erosion occurs in boilers due tothe impact of pulverized particles on burner lines andother components between the pulverizers and burn-ers. The erosiveness test, developed by B&W, subjectsa steel coupon to a stream of pulverized coal undercontrolled conditions. The measured weight loss of thecoupon indicates the erosiveness of the coal.

Slag viscosity The viscosity of a coal ash slag ismeasured at various temperatures under oxidizingand reducing conditions using a high temperature ro-tational bob viscometer. This viscometer and its appli-cation are described in more detail in Chapter 21. Thedata obtained from slag viscosity measurements areused to predict a coals slagging behavior in pulver-

ized coal-fired boiler applications. The results also in-dicate the suitability of a coal for use in B&Ws slag-ging and Cyclone furnaces.

Properties of selected coals

Table 6 gives basic fuel characteristics of typical U.S.coals. The coals are identified by state and rank, andthe analytical data include proximate and ultimateanalyses and HHVs. Table 7 provides similar fuel prop-erties of coals mined outside the U.S. The source of thisinformation, B&Ws Fuels Catalogue, contains morethan 10,000 fuel analyses performed and compiledsince the 1950s.

Fuels derived from coal

Because of abundant supplies and low prices, thedemand for coal as the prime or substitute fuel forutility boilers will most likely continue to increase. Inaddition, the future use of coal-derived fuels, such ascoal refined liquids and gases, coal slurries, and chars,as inexpensive substitutes for oil and natural gas, isalso possible. Therefore, methods to obtain clean and

efficiently burning fuels derived from coal are continu-ally being investigated. A few of these fuels that ap-ply to steam generation are discussed below.

Coke

When coal is heated in the absence of air or with alarge deficiency of air, the lighter constituents arevolatilized and the heavier hydrocarbons crack, lib-erating gases and tars and leaving a residue of car-bon. Some of the volatilized portions crack on contactwith the hot carbon, leaving an additional quantityof carbon. The carbonaceous residue containing theash and some of the original coal sulfur is called coke.The amount of sulfur and ash in the coke mainly de-

pends on the coal from which it is produced and thecoking process used. The principal uses for coke arethe production of pig iron in blast furnaces and thecharging of iron foundry cupolas. Because it is smoke-less when burned, considerable quantities have beenused for space heating.

Undersized coke, called coke breeze, usually pass-ing a 0.625 in. (15.875 mm) screen, is unsuitable forcharging blast furnaces and is often used for steamgeneration. A typical analysis of coke breeze appearsin Table 8. Approximately 4.5% of the coal supplied toslot-type coke ovens is recovered as coke breeze. Aportion of the coal tars produced as byproducts of thevarious coking processes may be burned in equipment

similar to that used for heavy petroleum oil.Gaseous fuels from coal

A number of gaseous fuels are derived from coal asprocess byproducts or from gasification processes. (See

Fig. 10 Coal burning profiles.




Chapter 18.) Table 9 lists selected analyses of thesegases. They have currently been largely supplantedby natural gas and oil. However, improvements in coalgasification and wider use of coal in the chemical andliquid fuel industries could reverse this trend.

Coke oven gasA considerable portion of coal is con-verted to gases in the production of coke. Valuableproducts recovered from these gaseous portions includeammonium sulfate, oils and tars. The non-condens-able portion is called coke oven gas. Constituents de-pend on the nature of the coal and the coking processused (Table 9).

Part of the sulfur from coal may be present in cokeoven gas as hydrogen sulfide and carbon disulfide.These may be removed by scrubbing. Coke oven gasoften contains other impurities that deposit in pipe-lines and burners. The gas burns readily because ofits high free hydrogen content and presents minimalproblems when used as steam generation fuel.

Blast furnace gas The gas discharged from steel millblast furnaces is used at the mills in furnaces, in gasengines and for steam generation. Blast furnace gashas variable quality but generally has a high carbonmonoxide (CO) content and low heating value (Table 9)This gas may be burned for steam generation. However

blast furnace gas deposits adhere firmly and provisionsmust be made for cleaning boiler heating surfaces.Water gas The gas produced by passing steam

through a bed of hot coke is known as water gas. Carbon in the coke combines with the steam to form Hand CO. This is an endothermic reaction that cools thecoke bed. Water gas is often enriched with oil by passing the gas through a checkerwork of hot brickssprayed with oil. The oil, in turn, is cracked to a gasby the heat. Refinery gas is also used for enrichmentIt may be mixed with the steam and passed throughthe coke bed or may be mixed directly with the watergas. Such enriched gas is called carbureted water gas

Table 6Properties of U.S. Coals

Upper

Pittsburgh #8 Illinois #6 Freeport Spring Creek Decker

HV HV MV Subbitu- Subbitu- Lignite Lignite Lignite

Anthracite Bituminous Bituminous Bituminous minous minous Lignite (S.Hallsville) (Bryan) (San Miguel)

State Ohio or Pa. Illinois Pennsylvania Wyoming Montana North Dakota Texas Texas Texas

Proximate:Moisture 7.7 5.2 17.6 2.2 24.1 23.4 33.3 37.7 34.1 14.2

Volatile matter, dry 6.4 40.2 44.2 28.1 43.1 40.8 43.6 45.2 31.5 21.2

Fixed carbon, dry 83.1 50.7 45.0 58.5 51.2 54.0 45.3 44.4 18.1 10.0

Ash, dry 10.5 9.1 10.8 13.4 5.7 5.2 11.1 10.4 50.4 68.8

Heating value, Btu/lb:

As-received 11,890 12,540 10,300 12,970 9,190 9,540 7,090 7,080 3,930 2,740

Dry 12,880 13,230 12,500 13,260 12,110 12,450 10,630 11,360 5,960 3,200

MAF 14,390 14,550 14,010 15,320 12,840 13,130 11,960 12,680 12,020 10,260

Ultimate:

Carbon 83.7 74.0 69.0 74.9 70.3 72.0 63.3 66.3 33.8 18.4

Hydrogen 1.9 5.1 4.9 4.7 5.0 5.0 4.5 4.9 3.3 2.3

Nitrogen 0.9 1.6 1.0 1.27 0.96 0.95 1.0 1.0 0.4 0.29

Sulfur 0.7 2.3 4.3 0.76 0.35 0.44 1.1 1.2 1.0 1.2

Ash 10.5 9.1 10.8 13.4 5.7 5.2 11.1 10.4 50.4 68.8

Oxygen 2.3 7.9 10.0 4.97 17.69 16.41 19.0 16.2 11.1 9.01

Ash fusion temps, F

Reducing/Oxidizing: Red Oxid Red Oxid Red Oxid Red Oxid Red Oxid

ID 2220 2560 1930 2140 2750+ 2750+ 2100 2180

ST Sp. 2440 2640 2040 2330 2750+ 2750+ 2160 2300

ST Hsp. 2470 2650 2080 2400 2750+ 2750+ 2170 2320

FT 0.0625 in. 2570 2670 2420 2600 2750+ 2750+ 2190 2360

FT Flat 2750+ 2750+ 2490 2700 2750+ 2750+ 2370 2700

Ash analysis:

SiO2 51.0 50.58 41.68 59.60 32.61 23.77 29.80 23.32 62.4 66.85

Al2O3 34.0 24.62 20.0 27.42 13.38 15.79 10.0 13.0 21.5 23.62

Fe2O3 3.5 17.16 19.0 4.67 7.53 6.41 9.0 22.0 3.0 1.18

TiO2 2.4 1.10 0.8 1.34 1.57 1.08 0.4 0.8 0.5 1.46

CaO 0.6 1.13 8.0 0.62 15.12 21.85 19.0 22.0 3.0 1.76

MgO 0.3 0.62 0.8 0.75 4.26 3.11 5.0 5.0 1.2 0.42

Na2O 0.74 0.39 1.62 0.42 7.41 6.20 5.80 1.05 0.59 1.67

K2O 2.65 1.99 1.63 2.47 0.87 0.57 0.49 0.27 0.92 1.57P2O5 0.39 0.42 0.44 0.99

SO3 1.38 1.11 4.41 0.99 14.56 18.85 20.85 9.08 3.50 1.32

Note: HV = high volatile; MV = medium volatile; ID = initial deformation temp; ST = softening temp; FT = fluid temp; Sp. = spherical; Hsp. = hemispherical.

Red Oxid Red Oxid Red Oxid Red Oxid Red Oxid

2120 2420 2030 2160 2000 2210 2370 2470 2730 2750+

2250 2470 2130 2190 2060 2250 2580 2670 2750+ 2750+

2270 2490 2170 2220 2090 2280 2690 2760 2750+ 2750+

2310 2510 2210 2280 2220 2350 2900+ 2900+ 2750+ 2750+

2380 2750+ 2300 2300 2330 2400 2900+ 2900+ 2750+ 2750+




(Table 9). In many areas, carbureted water gas hasbeen replaced by natural gas.

Producer gas When coal or coke is burned with adeficiency of air and a controlled amount of moisture(steam), a product known asproducer gas is obtained.This gas, after removal of entrained ash and sulfur

compounds, is used near its source because of its lowheating value (Table 9).

Byproduct gas from gasification

Coal gasification processes are a source of syntheticnatural gas. There are many processes under devel-opment. The effluent gas from steam-oxygen coal gas-ification consists principally of H2, CO, CH4, CO2 andunreacted steam. The gas will also be diluted with N2if air is used as the oxygen source. Although the com-peting chemical reactions that coal undergoes duringgasification are complex, they usually include the re-action of steam and carbon to produce H2 and CO.

Some CH4 is produced by the reaction of carbon withH2 and by thermal cracking of the heavy hydrocar-bons in the coal. CO2 and heat needed for the processare produced by reaction of carbon with O2. Final gascomposition is modified by reaction between CO andsteam to produce H2 and CO2.

The products of coal gasification are often classifiedas low, intermediate and high Btu gases. Low Btu gashas a heating value of 100 to 200 Btu/SCF (3.9 to 7.9MJ/Nm3) and is produced by gasification with airrather than oxygen. Typically, the gas is used as aboiler fuel at the gasification plant site or as feed to aturbine in combined cycles. Intermediate Btu gas hasa heating value of 300 to 450 Btu/SCF (11.8 to 17.7MJ/Nm3) and is produced by gasification with oxygenor by a process that produces a nitrogen-free product.The applications of intermediate Btu gas are similar tolow Btu gas. High Btu gas has a heating value greaterthan 900 Btu/SCF (35.4 MJ/Nm3) and is used as a fuel

Table 7Properties of Selected International Coals

Source Australia China France S. Africa Indonesia Korea Spain

Ultimate:

Carbon 56.60 62.67 74.60 69.70 56.53 68.46 37.02

Hydrogen 3.50 3.86 4.86 4.50 4.13 0.90 2.75

Nitrogen 1.22 0.83 1.39 1.60 0.88 0.20 0.88Sulfur 0.35 0.46 0.79 0.70 0.21 2.09 7.46

Ash 24.00 4.71 8.13 10.10 1.77 23.48 38.69

Oxygen 7.43 10.34 9.42 9.10 12.58 4.38 11.39

Proximate:

Moisture 6.90 17.13 0.80 4.30 23.90 0.50 1.80

Volatile matter, dry 24.80 30.92 36.11 35.30 45.57 7.46 45.27

Fixed carbon, dry 44.30 47.24 54.96 50.30 28.76 68.56 14.24

Ash, dry 24.00 4.71 8.13 10.10 1.77 23.48 38.69

Higher heating

value, Btu/lb 9660 10,740 13,144 12,170 9,840 9,443 6,098

Ash analysis:

SiO2

57.90 22.70 44.60 44.00 71.37 55.00 14.50

Al2O3 32.80 9.00 29.90 32.70 13.32 17.00 8.20

Fe2O3 6.20 15.68 13.10 4.60 7.00 12.50 2.70

TiO2 1.00 0.43 0.60 1.20 0.57 1.40 0.30

CaO 0.60 28.88 5.70 2.88 0.10 45.00MgO 0.80 2.00 3.50 1.30 0.53 0.10 1.20

Na2O 0.10 0.70 3.10 0.10 0.34 0.10 0.10

K2O 0.50 0.46 0.30 0.25 3.10 0.40P2O5 0.09 2.20 0.16 SO3 0.80 20.23 2.80 4.60 3.90

Ash fusion temps, F

Reducing/Oxidizing: Red Oxid Red Oxid Red Oxid Red Oxid Red Oxid Red Oxid Red Oxid

ID 2740 2750+ 2200 2220 2190 2300 2620 2670 2140 2410 2350 2600 2530 2520

ST Sp. 2750+ 2750+ 2240 2270 2310 2500 2750 2750+ 2400 2490 2630 2730 2700 2670

ST Hsp. 2750+ 2750+ 2250 2280 2750+ 2750+ 2450 2540 FT 0.0625 in. 2750+ 2750+ 2280 2290 2670 2820 2750+ 2750+ 2630 2680 2900 2900 2730 2740

FT Flat 2750+ 2750+ 2340 2320 2750+ 2750+ 2750 2750+




in place of natural gas. High Btu gas is produced by the

same gasification process as intermediate Btu gas andthen upgraded by methanation. (See also Chapter 18.)

Fuel oil

One of the most widely accepted theories explain-ing the origin of oil is the organic theory. Over mil-lions of years, rivers carried mud and sand that de-posited and ultimately became sedimentary rock for-mations. Along with this inorganic material, tinymarine organisms were buried with the silt. Over time,in an airless and high pressure environment, the or-ganic material containing carbon and hydrogen wasconverted to the hydrocarbon molecules of petroleum

(oil). Because of the porosity of sedimentary rock for-mations, the oil flowed and collected in traps, or loca-tions where crude oil is concentrated. This phenomenongreatly assists the economic recovery of crude oil.

Fuel oil consumption for steam generation accountsfor a minor share of U.S. domestic petroleum fuel usage. Industrial users, excluding transportation, account for about 25% of all petroleum use; electric utili-ties consume about 2% of the total.2 The end users ofpetroleum products for the years 1975 to 2000 areshown in Fig. 11. Crude oil reserves and world petro-leum consumption are shown in Figs. 12 and 13.

Compared to coal, fuel oils are relatively easy tohandle and burn. There is less bulk ash to dispose ofand the ash discharged is correspondingly small. Inmost oil burners, the fuel is atomized and mixed withcombustion air. In the atomized state, the characteristics of oil approach those of natural gas. (See Chapter 11.

Because of its relatively low cost, No. 6 fuel oil isthe most widely used for steam generation. It can beconsidered a byproduct of the refining process. Its ashcontent ranges from 0.01 to 0.5% which is very lowcompared to coal. However, despite this low ash con-tent, compounds of vanadium, sodium and sulfur inthe ash can pose operating problems. (See Chapter 21.)

Fuel oil characterization

Fuel oils include virtually all petroleum productsthat are less volatile than gasoline. They range fromlight oils, suitable for use in internal combustion orturbine engines, to heavy oils requiring heating. The

MillionBarrelsperDay

20

15

10

5

0

Year

1975

1980

1985

1990

1995

2 0 0 0

Fig. 11 U.S. petroleum end users.

Table 9Selected Analyses of Gaseous Fuels Derived from Coal

BlastCoke Oven Furnace Carbureted Producer

Gas Gas Water Gas GasAnalysis No. 1 2 3 4

Analyses, % by volumeHydrogen, H2 47.9 2.4 34.0 14.0

Methane, CH4 33.9 0.1 15.5 3.0Ethylene, C2H4 5.2 4.7 Carbon monoxide, CO 6.1 23.3 32.0 27.0Carbon dioxide, CO2 2.6 14.4 4.3 4.5Nitrogen, N2 3.7 56.4 6.5 50.9Oxygen, O2 0.6 0.7 0.6Benzene, C6H6 2.3 Water, H2O 3.4

Specific gravity 0.413 1.015 0.666 0.857(relative to air)

HHVBtu/ft3(kJ/m

3)

at 60F (16C) and 590 534 16330 in. Hg (102 kPa) (21,983) (19,896) (6,073)at 80F (27C) and 83.8 30 in. Hg (102 kPa) (3,122) (3,122) Fig. 12 Major world crude oil reserves, 2000 (OPEC = Organization

of Petroleum Exporting Countries).

BillionsofBar

rels

300

250

200

150

100

50

0

* Non-OPEC Country

261.7

112.597.8 96.5 89.7

76.957.1

28.3 2224

Saudi

Arabia

Iraq

UnitedArab

Emirates

Kuwait

Iran

Venezuela

FSU*

Mexico*

U.S.*

China*

Table 8AnalysesBagasse and Coke Breeze

Analyses (as-fired), Coke% by wt Bagasse Breeze

ProximateMoisture 52.0 7.3Volatile matter 40.2 2.3

Fixed carbon 6.1 79.4Ash 1.7 11.0

UltimateHydrogen, H2 2.8 0.3Carbon, C 23.4 80.0Sulfur, S trace 0.6Nitrogen, N2 0.1 0.3Oxygen, O2 20.0 0.5Moisture, H2O 52.0 7.3Ash 1.7 11.0

Heating value, Btu/lb 4000 11,670(kJ/kg) (9304) (27,144)




heavier fuels are primarily suited for steam genera-tion boilers. The ASTM specifications for fuel oil prop-erties are given in Table 10.

Fuel oils can be divided into two classes: distillateand residual. Distillate fuels are those that are vapor-ized in a petroleum refining operation. They are typi-cally clean, essentially free of sediment and ash, andrelatively low in viscosity. These fuels fall into the No.1 or No. 2 category in ASTM D 396. Although No. 2

oil is sometimes used as a premium steam generationfuel, it best lends itself to applications where cleanli-ness and ease of handling outweigh its cost. Examplesinclude home heating and industrial applicationswhere low ash and/or sulfur are important. Steamgenerating applications are primarily limited to useas a startup or support fuel.

Table 10ASTM Standard Specifications for Fuel Oilsa

No. 1 A distillate oil intended for vaporizing pot-type burnersand other burners requiring this grade of fuel

No. 2 A distillate oil for general purpose domestic heating foruse 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 climateand equipment

No. 5 (Heavy) Preheating may be required for burning and, incold climates, may be required for handling

No. 6 Preheating required for burning and handling

Notes:

a. Recognizing the necessity for low sulfur fuel oils used in connectionwith heat treatment, nonferrous metal, glass, and ceramic furnaces

and other special uses, a sulfur requirement may be specified inaccordance with the following table:

Grade ofFuel Oil Sulfur, Max, %

No. 1 . . . . . . . . . . . . . . . . . . 0.5No. 2 . . . . . . . . . . . . . . . . . . 0.7No. 4 . . . . . . . . . . . . . . . . . . no limitNo. 5 . . . . . . . . . . . . . . . . . . no limitNo. 6 . . . . . . . . . . . . . . . . . . no limit

Other sulfur limits may be specified only by mutual agreementbetween the purchaser and the seller.

b. It is the intent of these classifications that failure to meet anyrequirement of a given grade does not automatically place an oil in

the next lower grade unless, in fact, it meets all requirements ofthe lower grade.

c. Lower or higher pour points may be specified whenever required

by conditions of storage or use.

d. The 10% distillation temperature point may be specified at 440F(226C) maximum for use in other than atomizing burners.

e. When pour point less than 0F is specified, the minimum viscosityshall be 1.8 cs (32.0 s, Saybolt Universal) and the minimum 90%point shall be waived.

f. Viscosity values in parentheses are for information only and notnecessarily limiting.

g. The amount of water by distillation plus the sediment by extractionshall not exceed 2.00%. The amount of sediment by extractionshall not exceed 0.50%. A deduction in quantity shall be made forall water and sediment in excess of 1.0%.

Source, ASTM D 396.

Min Max Max Max Max Max Min Max Min Max

No. 1 100 or 0 trace 0.15 420 550 legal (216) (288)(38)

No. 2 100 or 20c 0.10 0.35 d 540c 640 (32.6)f (37.93)legal (-7) (282) (338)

(38)No. 4 130 or 20 0.50 0.10 45 125

legal (-7) (55)

No. 5 130 or 1.00 0.10 150 300(Light) legal

(55)

No. 5 130 or 1.00 0.10 350 750(Heavy) legal (55)

No. 6 150 2.00g (900) (9000) (65)

Min Max Min Max Min Max Min Max

1.4 2.2 35 . 3

2.0e 3.6 30

(5.8) (26.4)

(32) (65)

(23) (40) (75) (162) (42) (81)

45 300 (92) (638)

DistillationWater Carbon Temperatures, Kinematic Viscosity,

Grade Flash Pour and Residue F (C) Saybolt Viscosity, s centistokes Copperof Point, Point, Sediment, on 10% Ash Gravity, Strip

Fuel F F % by Bottoms, % by 10% 90% Universal at Furol at At 100F At 122F deg Cor-Oilb (C) (C) vol % wt Point Point 100F (38C) 122F (50C) (38C) (50C) API rosion

The residual fuel oils are those that are not vapor-ized by heating. They contain virtually all the inor-ganic constituents present in the crude oil. Frequently,residual oils are black, high viscosity fluids that re-quire heating for proper handling and combustion.

Fuel oils in grades No. 4 and 5 are less viscous andtherefore more easily handled and burned than is No.6 oil. Depending on the crude oil used, a fuel meetingthe No. 4 specification may be a blend of residual oil

and lighter distillate fractions. This oil does not usu-ally require heating for pumping and handling.

No. 5 oils may require heating, depending on thefiring equipment and the ambient temperature. No.6 oils usually require heating for handling and burn-ing. (See Chapter 11 for oil storage, handling and userequirements.)




Fuel analyses

A typical analysis of a fuel oil or waste liquid con-tains the following information:

1. ultimate analysis2. API gravity3. heating value4. viscosity5. pour point6. flash point7. water and sediment

Ultimate analysis The ultimate analysis for an oil issimilar to that for a coal. The results indicate the quan-tities of sulfur, hydrogen, carbon, nitrogen, oxygenand ash. Ultimate analyses for various fuel oils aregiven in Table 11.

The sulfur content of the oil is an indicator of its

corrosiveness and is oxidized to sulfur oxides duringcombustion. These oxides can react with water vaporor ash constituents to form corrosive acids, salts, orboiler fouling potassium sulfate. When molten, theseash deposits are corrosive. Furthermore, vanadiumcan combine with the sulfur oxides to form a corro-sive product. (See Chapter 21.)

API gravity The petroleum industry uses the APIgravity scale to determine the relative density of oil.The scale was devised jointly by the American Petro-leum Institute (API) and the National Bureau of Stan-dards. The relationship between theAPI gravity andthe specific gravity is given by the following formula:

Deg API Gravity

Specific gravity at 60/60F

=

141 5

131 5.

.

Given this relationship, heavier liquid fuels are de-noted by lower API gravity values.

Heating value The heating value of a liquid fuel in-dicates the heat released by the complete combustionof one unit of fuel [lb (kg)]. As for coal, there are twocalculated heating values, higher (HHV) and lower(LHV). In computing the HHV, it is assumed that anywater vapor formed by burning the hydrogen constitu-

ent is condensed and cooled to its initial temperatureTherefore, the heat of vaporization of the water formedis included in the HHV. For the LHV, it is assumed thatnone of the water vapor condenses. Both heating valuesare determined by using an oxygen bomb calorimeter.

Viscosity The viscosity of a liquid is the measure ofits internal resistance to flow. Although there are nu-merous viscosity scales, those most commonly used inthe U.S. are:

1. Saybolt Universal Seconds (SUS),2. Saybolt Furol Seconds (SFS),3. absolute viscosity (centipoise), and4. kinematic viscosity (centistokes).

The kinematic viscosity of oil is related to the absolute viscosity by the following formula:

Kinematic viscosity (centistokes)

Absolute viscosity (cen

=

ttipoise)

Specific gravity

Pour point The pour point is the lowest tempera-ture at which a liquid fuel flows under standardizedconditions.

Flash point The flash point is the temperature towhich a liquid must be heated to produce vapors thatflash but do not burn continuously when ignitedThere are two instruments used to determine the flashpoint: the Pensky-Martens or closed cup flash testerand the Cleveland or open cup tester. The closed cuptester indicates a lower flash point because it retainslight vapors which are lost by the open cup unit.

Water and sedimentThe water and sediment levelalso called bottom sediment and water (BSW), is ameasure of the contaminants in a liquid fuel. The sediment normally consists of calcium, sodium, magnesium

and iron compounds. For heavy fuels, the sedimentmay also contain carbon.

The basic analyses described are important in designing oil-fired boilers. The HHV determines thequantity of fuel required to reach a given heat inputThe ultimate analysis determines the theoretical airrequired for complete combustion and therefore indicates the size of the burner throat. Also available fromthe ultimate analysis is the carbon/hydrogen ratiowhich shows the ease with which a fuel burns. Thisratio also indicates the expected level of carbon par-ticulate emissions. A carbon/hydrogen ratio in excessof 7.5 is usually indicative of troublesome burning.

Considering the percentages of nitrogen and sulfur in conjunction with the HHV, an estimate of NOxand SO2 emissions can be made. The ash percentagehas a similar bearing on particulate emissions. The ashconstituent analysis and ash content indicate foulingand corrosion tendencies.

Additional information, which is often requiredwhen designing a boiler, includes:

1. carbon residue,2. asphaltenes,3. elemental ash analysis,4. burning profile, and5. distillation curve.

ThousandBarrelsperDay

30,000

25,000

20,000

15,000

10,000

5,000

0

North

America

Central

andSouth

America

Western

Europe

Eastern

Europe

andFSU

Middle

East

Africa

FarEast

andOceania

1980

1989

2000

20,2

04

20,7

502

3,7

75

13,9

47

12,8

80

14,6

72

3,5

73

3,6

12

5,1

31

11,0

82

10,5

67

4,7

73

4,4

56

3,1

17

2,0

58

1,4

74

2,0

04

2,4

40

10,7

33

12,8

68

20,7

73

Fig. 13 Major petroleum consumption.




Properties of fuel oilsAnalytical results for various fuel oil properties are

given in Table 11.Fuel oil heating values are closely related to their

specific gravities. The relationships between the HHVof various fuel oils and their API gravities are shownin Fig. 14.

A more accurate estimate of the heating value foran oil is obtained by correcting the HHVfrom Fig. 14as follows:

Apparent heating value

SS

=

+ +( ) +HHV A M 100

100

40 5.(7)

where

A = % weight of ashM = % weight of waterS = % weight of sulfur

The volume percentages of water and sediment canbe used without appreciable error in place of theirweight percentages.

Fuel oils are generally sold on a volume basis us-ing 60F (16C) as the base temperature. Correctionfactors are given in Fig. 15 for converting volumes at

Fig. 14 Relationship between HHV of various fuel oils and their APIgravities.

Table 11Analyses of Fuel Oils

Grade of Fuel Oil No. 1 No. 2 No. 4 No. 5 No. 6

% by weight:

Sulfur 0.01 to 0.5 0.05 to 1.0 0.2 to 2.0 0.5 to 3.0 0.7 to 3.5

Hydrogen 13.3 to 14.1 11.8 to 13.9 (10.6 to 13.0)* (10.5 to 12.0)* (9.5 to 12.0)*

Carbon 85.9 to 86.7 86.1 to 88.2 (86.5 to 89.2)* (86.5 to 89.2)* (86.5 to 90.2)*

Nitrogen nil to 0.1 nil to 0.1

Oxygen

Ash 0 to 0.1 0 to 0.1 0.01 to 0.5

Gravity:

Deg API 40 to 44 28 to 40 15 to 30 14 to 22 7 to 22

Specific 0.825 to 0.806 0.887 to 0.825 0.966 to 0.876 0.972 to 0.922 1.022 to 0.922

lb/gal 6.87 to 6.71 7.39 to 6.87 8.04 to 7.30 8.10 to 7.68 8.51 to 7.68

Pour point, F 0 to 50 0 to 40 10 to +50 10 to +80 +15 to +85

Viscosity:

Centistokes at 100F 1.4 to 2.2 1.9 to 3.0 10.5 to 65 65 to 200 260 to 750

SUS at 100F 32 to 38 60 to 300

SFS at 122F 20 to 40 45 to 300

Water and sediment, % by vol 0 to 0.1 tr to 1.0 0.05 to 1.0 0.05 to 2.0

Heating value, Btu/lb 19,670 to 19,860 19,170 to 19,750 18,280 to 19,400 18,100 to 19,020 17,410 to 18,990gross (calculated)

*Estimated




other temperatures to this standard base. This correc-tion is also dependent on the API gravity range, asillustrated by the three lines of Fig. 15.

Handling and burning equipment are usually de-signed for a maximum oil viscosity. If the viscositiesof heavy oils are known at two temperatures, theirviscosities at other temperatures can be closely pre-dicted by a linear interpolation between these twovalues on the standard ASTM chart (Fig. 16). Viscosity-temperature variations for certain light oils can also befound using the ASTM chart. In this case, however, thedesigner only needs to know the viscosity at one tem-perature. For example, the viscosity of a light oil at agiven temperature within the No. 2 fuel oil range canbe found by drawing a line parallel to the No. 2 bound-ary lines through the point of known temperature.

Natural gas

Past consumption and availability

Natural gas is found in porous rock in the earthscrust. World natural gas production for 1999 is shownin Fig. 17.

Electric power generation is the fastest growing seg-ment of U.S. natural gas consumption. By 2000, elec-tric generators had overtaken the residential segmentas the second largest user of natural gas with a 22%share of U.S. consumption (Table 12). Environmen-tal regulations, higher efficiency gas turbines, and alarge base of simple and combined cycle gas turbineplants installed in the late 1990s and early 2000s drovethe annual usage of natural gas in the U.S., for elec-tric power generation, from 3.8 trillion cubic feet in 1996to 5.5 trillion cubic feet in 2002. The Department ofEnergy (DOE) expects that the volatile price of naturalgas will hold growth to about 1.8% per year to 2025.

Natural gas characteristics

Natural gas can be found with petroleum reservesor in separate reservoirs. Methane is the principal component of natural gas; smaller components include

ethane, propane and butane. Other hydrocarbons, suchas pentane through decane, can also be found in natural gas. Furthermore, other gases such as CO2, nitrogenhelium and hydrogen sulfide (H2S) may be present.

Gas containing mostly methane is referred to as leangas.Wetgas contains appreciable amounts of the higherhydrocarbons (5 to 10% C). Gas containing H2S is sourgas; conversely, sweet gas contains little or no H2S.

40,000

35,000

30.000

25.000

20,000

15,000

10,000

5,000

0

North

America

Central

andSouth

America

Western

Europe

Eastern

Europe

andFSU

Middle

East

Africa

FarEast

andOceania

32,7

59

26,3

83

11,5

03

9,9

23

3,1

48

25,6

80

25,4

09

6,9

301

0,3

52

8,2

39

4,0

16

9,9

80

9,1

02

5,3

44

Gross

Dry

Production,

Billionft

Fig. 17 World natural gas production, 1999.

Fig. 16 Approximate viscosity of fuel oil at various temperatures(courtesy of ASTM).

Note: On the Y axis, find the SUS viscosity at 100F (standardtest temperature) for the given oil; move horizontally to the ver-tical line for 100F. From this intersection, move parallel to thediagonal lines to the viscosity required for atomization; the tem-perature necessary to achieve this viscosity can be read on theX axis. The chart, based on U.S. Commercial Standard 12-48,has been developed from data for many fuels and should besufficiently accurate for most applications.

Fig. 15 Oil volume-temperature correction factors.




Of all chemical fuels, natural gas is considered tobe the most desirable for steam generation. It is pipeddirectly to the consumer, eliminating the need for stor-age. It is substantially free of ash and mixes easilywith air, providing complete combustion withoutsmoke. Although the total hydrogen content of natu-ral gas is high, its free hydrogen content is low. Be-cause of this, natural gas burns less easily than somemanufactured gases with high free hydrogen content.

The high hydrogen content of natural gas comparedto that of oil or coal results in more water vapor beingproduced in the combustion gases. This results in acorrespondingly lower efficiency of the steam gener-ating equipment. (See Chapter 10.) This can readilybe taken into account when designing the equipment.

Properties of natural gas

Analyses of natural gas from several U.S. fields aregiven in Table 13.

Other fuels

While coal, oil and gas are the dominant fuelsources, other carbonaceous fuels being used for boilerapplications include petroleum byproducts and heavyhydrocarbon emulsions; wood, its byproducts and

wastes from wood processing industries; certain typesof vegetation, particularly bagasse; and municipalsolid waste.

Coke from petroleum

The heavy residuals from petroleum cracking pro-cesses are presently used to produce a higher yield oflighter hydrocarbons and a solid residue suitable forfuel. Characteristics of these residues vary widely anddepend on the process used. Solid fuels from oil includedelayed coke, fluid coke and petroleum pitch. Someselected analyses are given in Table 14.

The delayed coking process uses residual oil that is

heated and pumped to a reactor. Coke is deposited inthe reactor as a solid mass and is subsequentlystripped, mechanically or hydraulically, in the form oflumps and granular material. Some cokes are easy topulverize and burn while others are difficult.

Fluid coke is produced by spraying hot residual feedonto externally heated seed coke in a fluidized bed.The fluid coke is removed as small particles, which arebuilt up in layers. This coke can be pulverized andburned, or it can be burned in a Cyclone furnace orin a fluidized bed. All three types of firing requiresupplemental fuel to aid ignition.

The petroleum pitch process is an alternate to thecoking process and yields fuels of various character-istics. Melting points vary considerably, and the physi-

Table 13Selected Samples of Natural Gas from U.S. Fields

Sample No. 1 2 3 4 5

Source: Pa. S.C. Ohio La. Ok.

Analyses:Constituents, % by volH2, Hydrogen 1.82 CH4, Methane 83.40 84.00 93.33 90.00 84.10

C2H4, Ethylene 0.25 C2H6, Ethane 15.80 14.80 5.00 6.70CO, Carbonmonoxide 0.45

CO2, Carbondioxide 0.70 0.22 0.80

N2, Nitrogen 0.80 0.50 3.40 5.00 8.40O2, Oxygen 0.35 H2S, Hydrogensulfide 0.18

Ultimate, % by wtS, Sulfur 0.34 H, Hydrogen 23.53 23.30 23.20 22.68 20.85C, Carbon 75.25 74.72 69.12 69.26 64.84N, Nitrogen 1.22 0.76 5.76 8.06 12.90O, Oxygen 1.22 1.58 1.41

Specific gravity

(rel to air) 0.636 0.636 0.567 0.600 0.630HHV

Btu/ft3 at 60Fand 30 in. Hg 1,129 1,116 964 1,022 974(kJ/m3 at 16Cand 102 kPa) (42,065) (41,581) (35,918) (38,079) (36,290)

Btu/lb(kJ/kg) 23,170 22,904 22,077 21,824 20,160of fuel (53,893) (53,275) (51,351) (50,763) (46,892)

Table 14

Selected Analyses of Solid Fuels Derived from Oil

Analyses (dry basis)% by wt Delayed Coke Fluid Coke

Proximate:VM 10.8 9.1 6.0 6.7FC 88.5 90.8 93.7 93.2Ash 0.7 0.1 0.3 0.1

Ultimate:Sulfur 9.9 1.5 4.7 5.7

Heating value,Btu/lb 14,700 15,700 14,160 14,290(kJ/kg) (34,192) (36,518) (32,936) (33,239)

Table 12U.S. Natural Gas Consumption (Trillion ft3)

Resi- Com- Indus- Elec. Transpor-Year dential mercial trial Power tation Total

1989 4.78 2.72 7.89 3.11 0.63 19.121990 4.39 2.62 8.26 3.25 0.66 19.171991 4.56 2.73 8.36 3.32 0.60 19.561992 4.69 2.80 8.70 3.45 0.59 20.231993 4.96 2.86 8.87 3.47 0.63 20.791994 4.85 2.90 8.91 3.90 0.69 21.251995 4.85 3.03 9.38 4.24 0.71 22.211996 5.24 3.16 9.69 3.81 0.72 22.611997 4.98 3.22 9.71 4.07 0.76 22.741998 4.52 3.00 9.49 4.57 0.65 22.251999 4.73 3.05 9.16 4.82 0.66 22.412000 5.00 3.22 9.29 5.21 0.66 23.372001 4.78 3.04 8.45 5.34 0.64 22.252002 4.91 3.11 8.23 5.55 0.65 22.46

Note: Total may not equal sum of components due toindependent rounding. Source: Energy Information

Administration,Annual Energy Review, 2003.


19/334




Hogged wood and bark are very bulky and requirerelatively large handling and storage equipment. Un-interrupted flow from bunkers or bins through chutesis difficult to maintain. (Also see Chapter 30.)

Wood wastesThere are several industries usingwood as a raw material where combustible byproductsor wastes are available as fuels. The most importantof these are the pulp and turpentine industries. Thenature and methods of utilization of the combustible

byproducts from the pulp industry are discussed inChapter 28.

The residue remaining after the steam distillationof coniferous woods for the production of turpentineis usable as a fuel. Some of the more easily burnedconstituents are removed in the distillation process; asa result, the residue is somewhat more difficult to burn.Other than this, fuel properties are much the sameas those of the raw wood and the problems involvedin utilization are similar.

Bagasse

Mills grinding sugar cane commonly use bagassefor steam production. Bagasse is the dry pulp remain-

ing after the juice has been extracted from sugar cane.The mills normally operate 24 hours per day duringthe grinding season. The supply of bagasse will eas-ily meet the plant steam demands in mills where thesugar is not refined. Consequently, where there is noother market for the bagasse, no particular effort ismade to burn it efficiently, and burning equipment isprovided that will burn the bagasse as-received fromthe grinders. In refining plants, supplemental fuelsare required to provide the increased steam demands.Greater efforts to obtain higher efficiency are justi-fied in these plants. A selected analysis of bagasse isgiven in Table 8.

Other vegetation wastesFood and related industries produce numerous veg-

etable wastes that are usable as fuels. They includesuch materials as grain hulls, the residue from the

Table 17Analyses of MSW and RDF Compared to Bituminous Coal

Analyses, % by wt

Constituent MSW RDF Bituminous Coal

Carbon 27.9 36.1 72.8Hydrogen 3.7 5.1 4.8Oxygen 20.7 31.6 6.2Nitrogen 0.2 0.8 1.5Sulfur 0.1 0.1 2.2Chlorine 0.1 0.1 0Water 31.3 20.2 3.5Ash 16.0 6.0 9.0HHV (wet), Btu/lb 5,100 6,200 13,000

(kJ/kg) (11,863) (14,421) (30,238)

Orimulsion is a trademark of Bitumenes Orinoco, S.A.

1. International Energy Outlook 2003, Report DOE/EIA-0484 (2003), United States (U.S.) Energy Information Ad-ministration, Washington, D.C., May, 2003.

2. Annual Energy Review 2001, Report DOE/EIA-0384(2001), U.S. Energy Information Administration, Wash-ington, D.C., November, 2002.

3. 2001 Survey of Energy Resources, World Energy Con-gress, London, England, 2001.

4. Coal Industry Annual 2000, Report DOE/EIA-0584(2000), U.S. Energy Information Administration, Wash-ington, D.C., 2001.

5. Gaseous Fuels; Coal and Coke, Vol. 05.05, AnnualBook of ASTM Standards, American Society for Testingand Materials, West Conshohocken, Pennsylvania, 1999.

6. Parr, S.W., The Classification of Coal, Bulletin No.180, Engineering Experiment Station, University of Illi-nois, Chicago, Illinois, 1928.

7. Vecci, S.J., Wagoner, C.L., and Olson, G.B., Fuel andAsh Characterization and Its Effect on the Design of In-dustrial Boilers,Proceedings of the American Power Con-

ference, Vol. 40, pp. 850-864, 1978.

8. Wagoner, C.L., and Duzy, A.F., Burning Profiles forSolid Fuels, Technical Paper 67-WA-FU-4, American So-ciety of Mechanical Engineers, New York, New York, 1967.

References

production of furfural from corn cobs and grain hulls,coffee grounds from the production of instant coffee,and tobacco stems. Fuels of this type are available insuch small quantities that they are relatively insig-nificant in total energy production.

Municipal solid waste

Municipal solid waste (MSW), or refuse, is an en-ergy source in the U.S., Europe and Japan. MSW isthe combined residential and commercial waste gen-erated in a given municipality. It is burned as-re-ceived, called mass burning, or processed using sizereduction and material recovery techniques to producerefuse-derived fuel (RDF). Much MSW continues tobe landfilled, since siting and acceptance of waste-to-energy boilers have been greatly limited by the publicsconcern over environmental issues.

Table 17 shows a typical analysis of raw refuse andRDF compared to bituminous coal. The relatively lowcalorific value and high heterogeneous nature of MSWprovide a challenge to the combustion system designengineer. The design of MSW handling and combus-tion systems is discussed in Chapter 29.




Coal remains the dominant fuel source for electric power generation worldwide.


22/334Steam 41 / Principles of Combustion 10-1


Chapter 10

Principles of Combustion

A boiler requires a source of heat at a sufficient tem-perature to produce steam.Fossil fuel is generallyburned directly in the boiler furnace to provide thisheat although waste energy from another process mayalso be used.

Combustion is defined as the rapid chemical com-bination of oxygen with the combustible elements ofa fuel.There are just three combustible elements ofsignificance in most fossil fuels: carbon, hydrogen and

sulfur.Sulfur, usually of minor significance as a heatsource, can be a major contributor to corrosion andpollution problems.(See Chapters 21 and 32.)

The objective of good combustion is to release all ofthe energy in the fuel while minimizing losses fromcombustion imperfections and excess air.System re-quirement objectives include minimizing nitrogenoxides (NOx), carbon monoxide (CO), volatile organiccompounds (VOC) and, for more difficult to burn fu-els, minimizing unburned carbon (UBC) and furnacecorrosion. The combination of the combustible fuel el-ements and compounds in the fuel with all the oxy-gen requires temperatures high enough to ignite theconstituents, mixing or turbulenceto provide intimateoxygen-fuel contact, and sufficient time to completethe process, sometimes referred to as the three Ts ofcombustion.

Table 1 lists the chemical elements and compoundsfound in fuels generally used in commercial steamgeneration.

Concept of the mole

The mass of a substance in pounds equal to itsmolecular weight is called a pound-mole (lb-mole) ofthe substance.The molecular weight is the sum of theatomic masses of a substances constituent atoms.Forexample, pure elemental carbon (C) has an atomic massand molecular weight of 12 and therefore a lb-mole isequal to 12.In the case of carbon dioxide (CO2), car-bon still has an atomic mass of 12 and oxygen has anatomic mass of 16 giving CO2 a molecular weight and

a lb-mole equal to (1 12) + (2 16) or 44.In SI, asimilar system is based upon the molecular weight inkilograms expressed as kg-mole or kmole.In theUnited States (U.S.) power industry it is common prac-tice to replace lb-mole with mole.

In the case of a gas, the volume occupied by onemole is called the molar volume.The volume of onemole of an ideal gas (a good approximation in mostcombustion calculations) is a constant regardless of its

composition for a given temperature and pressure.Therefore, one lb-mole or mole of oxygen (O2) at 32 lband one mole of CO2 at 44 lb will occupy the samevolume equal to 394 ft3 at 80F and 14.7 psi.The vol-ume occupied by one mole of a gas can be corrected toother pressures and temperatures by the ideal gas law.

Because substances combine on a molar basis dur-ing combustion but are usually measured in units ofmass (pounds), the lb-mole and molar volume areimportant tools in combustion calculations.

Fundamental laws

Combustion calculations are based on several fun-damental physical laws.

Conservation of matter

This law states that matter can not be destroyed orcreated.There must be a mass balance between thesum of the components entering a process and the sumof those leaving: X pounds of fuel combined with Ypounds of air always results in X + Y pounds of prod-ucts (see Note below).

Conservation of energy

This law states that energy can not be destroyed orcreated.The sum of the energies (potential, kinetic,thermal, chemical and electrical) entering a process mustequal the sum of those leaving, although the proportionsof each may change.In combustion, chemical energy isconverted into thermal energy (see Note below).

Note: While the laws of conservation of matter and energyare not rigorous from a nuclear physics standpoint (see Chap-ter 47), they are quite adequate for engineering combustioncalculations. When a pound of a typical coal is burned re-leasing 13,500 Btu, the equivalent quantity of mass convertedto energy amounts to only 3.5 1010 lb.

For clarity, this chapter is provided in English units only.Appendix 1 provides a comprehensive list of conversion fac-tors. Selected factors of particular interest here include:Btu/lb 2.326 = kJ/kg; 5/9 (F-32) = C; lb 0.4536 = kg.Selected SI constants include: universal gas constant =8.3145 kJ/kmole K; one kmole at 0C and 1.01 bar = 22.4 m3.


23/334


24/334Steam 41 / Principles of Combustion 10-3


Ideal gas law

This law states that the volume of an ideal gas isdirectly proportional to its absolute temperature andinversely proportional to its absolute pressure.

The proportionality constant is the same for one moleof any ideal gas, so this law may be expressed as:

v

PM

=RT

(1)

where

Mv = volume, ft3/moleR = universal gas constant, 1545 ft lb/mole RT = absolute temperature, R = F + 460

P = absolute pressure, lb/ft2

Most gases involved in combustion calculations canbe approximated as ideal gases.

Law of combining weights

This law states that all substances combine in ac-cordance with simple, definite weight relationships.These relationships are exactly proportional to themolecular weights of the constituents.For example,carbon (molecular weight = 12) combines with oxygen(molecular weight of O2 = 32) to form carbon dioxide(molecular weight = 44) so that 12 lb of C and 32 lb ofO2 unite to form 44 lb of CO2.(SeeApplication of fun-damental laws below.)

Avogadros law

Avogadro determined that equal volumes of differ-ent gases at the same pressure and temperature con-tain the same number of molecules.From the conceptof the mole, a pound mole of any substance containsa mass equal to the molecular weight of the substance.

Therefore, the ratio of mole weight to molecular weightis a constant and a mole of any chemically pure sub-stance contains the same number of molecules.Be-cause a mole of any ideal gas occupies the same volumeat a given pressure and temperature (ideal gas law),equal volumes of different gases at the same pressureand temperature contain the same number of molecules.

Daltons law

This law states that the total pressure of a mixtureof gases is the sum of the partial pressures whichwould be exerted by each of the constituents if eachgas were to occupy alone the same volume as the mix-ture. Consider equal volumes Vof three gases (a, b

and c), all at the same temperature Tbut at differentpressures (Pa,Pb and Pc). When all three gases areplaced in the space of the same volume V, then theresulting pressurePis equal toPa+Pb+Pc.Each gasin a mixture fills the entire volume and exerts a pres-sure independent of the other gases.

Amagats law

Amagat determined that the total volume occupiedby a mixture of gases is equal to the sum of the vol-umes which would be occupied by each of the constitu-ents when at the same pressure and temperature asthe mixture.This law is related to Daltons law, but it

considers the additive effects of volume instead of pres-sure.If all three gases are at pressurePand tempera-ture Tbut at volumes Va, Vb and Vc, then, when com-bined so that TandPare unchanged, the volume ofthe mixture Vequals Va+Vb+Vc.

Application of fundamental laws

Table 2 summarizes the molecular and weight re-

lationships between fuel and oxygen for constituentscommonly involved in combustion.The heat of com-bustion for each constituent is also tabulated.Most ofthe weight and volume relationships in combustion cal-culations can be determined by using the informationpresented in Table 2 and the seven fundamental laws.

The combustion process for C and H2 can be ex-pressed as follows:

C + O2 = CO2

1 molecule + 1 molecule 1 molecule1 mole + 1 mole = 1 mole(See Note below) + 1 ft3 1 ft3

12 lb + 32 lb = 44 lb

2H2 + O2 = 2H2O

2 molecules + 1 molecule 2 molecules2 moles + 1 mole = 2 m

05.section ii_steam, its generation & use, 41_ed

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