Lefebvre A.H., Ballal D.R. Gas Turbine Combustion: Alternative Fuels and Emissions

Подождите немного. Документ загружается.

440 Gas Turbine Combustion: Alternative Fuels and Emissions, Third Edition

76. Santavicca, D. A., Steinberger, D. L., Gibbons, K. A., Citeno, J. V., and Mills, S.,

“The Effect of Incomplete Fuel-Air Mixing on the Lean Limit and Emissions

Characteristics of a Lean Prevaporized Premixed (LPP) Combustor,” AGARD

Conference Proceedings 536, AGARD, Paris-France, pp. 22/1–12, 1993.

77. Valk, M., private communication, 1994.

78. Martin, F. J., and Dederick, P. K. J., “NO

from Fuel Nitrogen in Two-Stage

Combustion,” Sixteenth Symposium (International) on Combustion, pp. 191–98,

The Combustion Institute, Pittsburgh, PA, 1976.

79. Nakata, T., Sato, M., Ninomiya, T., and Hasegawa, T., “A Study on Low NO

Combustion in LBG-Fueled 1500°C-Class Gas Turbine,” ASME Paper 94-GT-

218, 1994.

80. Talpallikar, M. V., Smith, C. E., Lai, M. C., and Holderman, J. D., “CFD Analysis of

Jet Mixing in Low NO

Flametube Combustors,” ASME Paper 91-GT-217, 1991.

81. Mosier, S. A., and Pierce, R. M., “Advanced Combustion Systems for Stationary

Gas Turbine Engines,” EPA Contract 68-02-2136, 1980.

82. Novick, A. S., Troth, D. L., and Yacobucci, H. G., “Design and Preliminary Results

of a Fuel Flexible Industrial Gas Turbine Combustor,” Journal of Engineering for

Power, Vol. 104, pp. 368–76, 1982.

83. Rizk, N. K., and Mongia, H. C., “Low NO

Rich-Lean Combustion Concept

Application,” AIAA Paper 91-1962, 1991.

84. Nakata, T., Sato, M., Ninomiya, T., Yoshine, T., and Yamada, M. “Design and

Test of a Low-NO

Advanced Rich-Lean Combustor for LBG Fueled 1300°C-

Class Gas Turbine,” ASME Paper 92-GT-234, 1992.

85. Feitelberg, A. S., and Lacey, M. A., “The GE Rich-Quench-Lean Gas Turbine

Combustor,” ASME Paper 97-GT-127, 1997.

86. Shaw, R. J., “Propulsion Challenges for a 21st Century Economically Viable,

Environmentally Compatible High-Speed Civil Transport,” Tenth International

Symposium on Air-Breathing Engines, ISABE 91-7008, AIAA, Washington, DC,

pp. 93–103, 1991.

87. Pfefferle, W. C., “Catalytically Supported Thermal Combustion,” U.S. Patent 3,

928, 961, 1975.

88. Kolaczkowski, S. T., “Catalytic Stationary Gas Turbine Combustors: A Review

of the Challenges Faced to Clear the Next Set of Hurdles,” Transactions of the

Institution of Chemical Engineers, Vol. 73, Part A, 1995.

89. Dalla Betta, R. A., Schlatter, J. C., Nickolas, S. G., Yee, D. K., and Shoji, T., “New

Catalytic Combustion Technology for Very Low Emissions Gas Turbines,”

ASME Paper 94-GT-260, 1994.

90. Dalla Betta, R. A., Schlatter, J. C., Nickolas, S. G., Razdan, M. K., and Smith, D. A.,

“Application of Catalytic Combustion Technology to Industrial Gas Turbines for

Ultra-Low NO

Emissions,” ASME Paper 95-GT-65, 1995.

91. Dalla Betta, R. A., Schlatter, J. C, Nickolas, S. G., Cutrone, M. B., Beebe, K. W.,

Furuse, Y., and Tsuchiya, T., “Development of a Catalytic Combustor for a

Heavy-Duty Utility Gas Turbine,” ASME Paper 96-GT-485, 1996.

92. Schlatter, J. C., Dalla Betta, R. A., Nickolas, S. G., Cutrone, M. B., and Beebe,

K. W., “Single-Digit Emissions in a Full Scale Catalytic Combustor,” ASME

Paper 97-GT-57, 1997.

93. Dutta, P., Cowell, L. H., Yee, D. K., and Dalla Betta, R. A., “Design and Evaluation

of a Single-Can Full Scale Catalytic Combustion System for Ultra-Low Emissions

Industrial Gas Turbines,” ASME Paper 97-GT-292, 1997.

Emissions 441

94. Dutta, P., Yee, D. K., and Dalla Betta, R. A., “Catalytic Combustor Development

for Ultra-Low Emissions Industrial Gas Turbines,” ASME Paper 97-GT-497,

1997.

95. Cowell, L. H., and Larkin, M. P., “Development of a Catalytic Combustor for

Industrial Gas Turbines,” ASME Paper 94-GT-254, 1994.

96. Ozawa, Y., Hirano, J., Sato, M., Saiga, M., and Watanabe, S., “Test Results of

Low NO

Catalytic Combustors for Gas Turbines,” Journal of Engineering for Gas

Turbines and Power, Vol. 116, pp. 511–16, 1994.

97. Fujii, T., Ozawa, Y., Kikumoto, S., and Sato, M., “High Pressure Test Results of a

Catalytic Combustor for Gas Turbine,” ASME Paper 96-GT-382, 1996.

98. Vortmeyer, N., Valk, M., and Kappler, G., “A Catalytic Combustor for High-

Temperature Gas Turbines,” Journal of Engineering for Gas Turbines and Power,

Vol. 118, No. 1, pp. 61–4, 1996.

99. Anderson, S. J., Friedman, M. A., Krill, W. V., and Kesselring, J. P., “Development

of a Small-Scale Catalytic Gas Turbine Combustor,” Journal of Engineering for

Power, Vol. 104, pp. 52–7, 1982.

100. Beebe, K. W., Cutrone, M. B., Mathews, R. N., Dalla Betta, R. A., Schlatter, J. C.,

Furuse, Y., and Tsuchiya, T., “Design and Test of a Catalytic Combustor for a

Heavy-Duty Industrial Gas Turbine,” ASME Paper 95-GT-137, 1995.

101. Beebe, K. W., Ohkoshi, A., Radak, L., and Weir, A., “Design and Test of Catalytic

Combustor Fuel-Air Preparation System,” Paper 51, Presented at 1987 Tokyo

International Gas Turbine Congress, Japan, October 26–31, 1987.

102. Lefebvre, A. H., “Fuel Effects on Gas Turbine Combustion—Liner Temperature,

Pattern Factor, and Pollutant Emissions,” Journal of Aircraft, Vol. 21, No. 11,

pp. 887–98, 1984.

103. Mellor, A. M., “Semi-Empirical Correlations for Gas Turbine Emissions, Ignition,

and Flame Stabilization,” Progress in Energy and Combustion Science, Vol. 6, No. 4,

pp. 347–58, 1981.

104. Odgers, J., and Kretschmer, D., “The Prediction of Thermal NO

in Gas Turbines,”

ASME Paper 85-1GT-126, 1985.

105. Lewis, G. D., “A New Understanding of NO

Formation,” Tenth International

Symposium on Air-Breathing Engines, ISABE 91-7064, Nottingham, UK, AIAA,

Washington, DC, pp. 625–9, 1991.

106. Rokke, N. A., Hustad, J. E., and Berg, S., “Pollutant Emissions from Gas Fired

Turbine Engines in Offshore Practice—Measurements and Scaling,” ASME Paper

93-GT-170, 1993.

107. Rizk, Ν. Κ., and Mongia, Η. C., “Emissions Predictions of Different Gas Turbine

Combustors,” AIAA Paper 94-0118, 1994.

108. Becker, T., and Perkavec, Μ. Α., “The Capability of Different Semianalytical

Equations for Estimation of NO

Emissions of Gas Turbines,” ASME Paper

94-GT-282, 1994.

109. Nicol, D. G., Make, P. C., and Steele, R. C., “Simplied Models for NO

Production

Rates in Lean-Premixed Combustion,” ASME Paper 94-GT-432, 1994.

110. Connors, C. S., Barnes, J. C., and Mellor, A. M., “Semiempirical Predictions and

Correlations of CO Emissions from Utility Combustion Turbines,” Journal of

Propulsion and Power, Vol. 12, No. 5, pp. 926–32, 1996.

111. Rizk, N. K., and Mongia, H. C., “Semianalytical Correlations for NO

, CO and

UHC Emissions,” Journal of Engineering for Gas Turbines and Power, Vol. 115, No.

3, pp. 612–19, 1993.

443

Alternative Fuels

10.1 Introduction

In the early days of gas turbine development, the view was widely held that

gas turbines are “omnivorous” machines, capable of operating efciently on

a wide variety of cheap fuels—solid, liquid, and gaseous. The choice of fuel

is dictated on the grounds of cost, availability, and ease of handling. This is

true even today, provided one keeps in mind the important and restrictive

effects of aircraft engine requirements on the physical and chemical proper-

ties of fuel.

Today, the ever-rising cost of petroleum fuel is prompting research into

developing alternative liquid fuels based on coal, biomass, and other feed-

stock. The terrorist activities in the Middle East are leading various indus-

trialized and developing countries to develop domestic sources of fuel and

energy. Finally, these domestically produced alternative fuels have to be

capable of using the available infrastructure of fuel rening, transportation,

distribution, and consumption.

In general, for any given aircraft application, the optimal fuel is the one

that represents the best compromise solution to the various problems con-

fronting the fuel companies, the engine and aircraft manufacturers, and

the operators. For civil aircraft, the main requirements are safety, reliability,

low cost, and ease of handling. For military aircraft, fuel cost is of second-

ary importance compared with availability, supply logistics, and the need

for trouble-free operation over a wide range of conditions. Industrial and

marine gas turbines can compete effectively with the diesel engine only

through the use of very cheap fuels, such as residual oil or surplus gas. As

a rule, gaseous fuels present no special problems, but residual oils produce

a highly destructive ash and sometimes copious amounts of exhaust smoke.

Attempts to burn pulverized solid fuels in open-cycle gas turbines have gen-

erally proved unsuccessful. However, developments in integrated gasica-

tion combined cycle (IGCC) plants employing coal gasier and uidized-bed

combustion are dramatically changing that situation.

The alternative synthetic liquid fuels of major interest will be largely

derived from biomass (carbohydrates, algae, and vegetation), coal, oil shale,

444 Gas Turbine Combustion: Alternative Fuels and Emissions, Third Edition

tar sands, and heavy oil. For longer term, methane and hydrogen are among

the candidate fuels now being considered. All these fuels must be compatible

with engine and fuel-system requirements and, where appropriate, with air-

craft design features and operational procedures. The main impact of trends

and developments relative to combustor design will be felt in fuel-nozzle

design for multifuel capability and in fuel and air management for mini-

mum soot and gaseous emissions. The future of the alternative fuel industry

depends on the following key factors:

Right fuel properties and handling for the engines and infrastruc-•

ture already in place,

Environmental impact that includes competition with food, water, •

and land,

CO•

life cycle analysis and carbon footprint issues,

Economics of return on investment, production, and sustainability.•

This chapter presents the physical and chemical properties of conventional

(petroleum-based) liquid and gaseous fuels for gas turbines. Next, alternative

(synthetic) fuels and conventional-alternative fuel blends are reviewed. The

inuence of these different fuels and their blends on combustor perfor-

mance and design are investigated. Reference is made to the special require-

ments of aircraft fuels and the problems encountered with industrial fuels.

Important aspects of oil production and supplies are discussed in recent

publications [1–7].

10.2 Types of Hydrocarbons

Pure hydrocarbon fuels are compounds of two elements only, carbon and

hydrogen. They may be gaseous, liquid, or solid at normal pressure and

temperature, depending on the number of carbon atoms and their molecu-

lar structure. Those with up to four carbon atoms are gaseous; those with

twenty or more are solid, and those in between are liquid [8]. It is usual to

classify the hydrocarbons present in petroleum fuel into four main groups:

parafnic, olenic, naphthenic, and aromatic. The proportions in which these

groups are present largely dene the character of the fuel.

10.2.1 Paraffins

Parafnic oils are found mainly in the United States, North Africa, and

Nigeria. They have the general formula C

2n + 2

. Thus, the simplest hydro-

carbon, methane, is in this class; its molecule can be represented as:

Alternative Fuels 445

H−C−H

Methane, CH

The remaining normal parafns are built up from methane as straight

chains, e.g.,

H H

| |

H−C−C−H

| |

H H

Ethane, C

| | |

−C−C−C−

| | |

Propane, C

Alternative parafn congurations, or isoparafns, are in the form of

branched chains, such as

| |

−CH−CH

−CH

Dimethyl hexane, C

(CH

)

Current aviation fuels contain an average of 60% parafns, depend-

ing on the source of the crude oil and the distillation process. In gen-

eral, parafns tend to have a higher hydrogen/carbon ratio, lower density,

lower freeze point, and high gravimetric caloric value than other types

of hydrocarbon fuels. They possess high thermal stability, and their com-

bustion is characterized by freedom from coke deposition and exhaust

smoke.

10.2.2 Olefins

Olens conform to the general formula C

. They do not normally exist

in crude oil, but are produced by conversion processes in the renery. As

olens are unsaturated, i.e., their molecules contain less than the maximum

possible number of hydrogen atoms, they are very active chemically and

readily react with a great many compounds to form resinous gums and rub-

berlike materials. For this reason, olens are very undesirable in gas turbine

fuels, and are found only in trace quantities.

446 Gas Turbine Combustion: Alternative Fuels and Emissions, Third Edition

Olen molecules must contain at least two carbon molecules, and the light-

est molecule is, therefore, C

, ethylene. More complex molecules of the

olen series are obtained by adding CH

, as in

| | | | | | | | |

C=C C=C−C− C = C−C−C−

| | | | | | |

Ethylene, C

Propylene, C

Butylene, C

10.2.3 Naphthenes

Naphthenes, which have the general formula (CH

)

, are saturated hydrocar-

bons in which the carbon atoms are linked to form rings instead of chains

as in the case of parafns. Naphthenes bear names identical to those of the

parafns that have the same number of carbon atoms, with the addition of

the prex “cyclo,” e.g.,

\ / \ /

C C

/ \ \ \ / \ /

−C−C− C C

/ \ / \ / \

− C − C−

\ /

Cyclopropane, C

Cyclopentane, C

Naphthenes are major constituents of jet fuel, i.e., about 25–35%. They

closely resemble parafns in their chemical stability, high gravimetric heat

of combustion, and low soot-forming tendencies.

10.2.4 Aromatics

Aromatics are ring compounds containing one or more six-member rings

with the equivalent of three double bonds. Although similar in structure to

the naphthenes, they contain less hydrogen and, in consequence, their spe-

cic energy is appreciably lower. Aromatic compounds in fuel cause swell-

ing of o-ring and this helps seal the high pressure aircraft fuel system. The

disadvantages of aromatic compounds include a marked tendency to soot

formation and a high hygroscopicity that can lead to precipitation of ice crys-

tals when the fuel is subjected to low temperatures. Aromatics also have a

strong solvent action on rubber that can cause trouble in fuel systems and on

aircraft tted with soft-rubber-lined fuel tanks.

Alternative Fuels 447

The characteristic formula for the aromatics is C

2n-6

. The simplest

member is benzene, in which each carbon atom carries only one hydrogen

atom:

// \

−C C−

| ||

−C C−

\\ /

Benzene, C

More complex molecules of the aromatic group are obtained either by

replacing one or more of the hydrogen atoms with hydrocarbon groups or by

“condensing” one or more rings [8]. Another example is:

// \

−C C−

| || |

−C C−C−

\\ / |

Toluene, C

Although aromatics are undesirable in gas turbine fuels, the proportion of

aromatics normally present in straight-run distillates is too high to justify

the expense of their removal. Current practice with aircraft fuels is to limit

the aromatic content to a maximum of 20% by volume [9].

In summary, the conventional petroleum-based jet fuel is a mixture of

many different hydrocarbons. Jet fuel has an average composition of 60%

parafns, 20% naphthenes, 20% aromatics and contains about 500 ppm

of sulfur. A broad specication allows signicant variation in composi-

tion. For example, wide-cut jet fuel has a formula of C

(MW = 140,

density = 0.78), aviation kerosine is C

(MW = 168, density = 0.8) and

average formula is C

(MW = 153, density = 0.79). Finally, commercial

and military fuel specications are very similar, except for slight varia-

tions. For example, Jet A (U.S.) has a higher freeze point (–51°C) than Jet

A-1 (international, –47°C) and JP-8 (U.S. Air Force) has extra additives

than Jet A-1. Figure 10.1 shows a gas chromatograph of the composition

of jet fuel.

448 Gas Turbine Combustion: Alternative Fuels and Emissions, Third Edition

10.3 Production of Liquid Fuels

The production process can be divided into three basic categories:

1. Separation process: Crude oil is separated into its primary frac-

tions, consisting of gasoline, distillate fuels, and fuel oil; these then

provide the basic material for the desired range of fuel products.

Separation is accomplished by a distillation process that exploits the

fact that the various components in crude oil have different boiling

points. When a crude oil is heated, the rst gases evolved are chiey

methane, ethane, propane, and butane. Next, vapors are released

that condense to form light distillates and then gasoline. As boiling

proceeds, kerosine emerges, followed by the middle distillates used

in gas oil and diesel fuel. Finally, a residue is left that is used in the

manufacture of lubricating oils, wax, and bitumen.

2. Upgrading process: These processes improve the quality by using

chemical reactions to remove any compounds present in trace

quantities. Commonly used upgrading processes are sweetening,

hydrotreating, and clay treatment.

3. Conversion process: These processes change the molecular structure

of the feedstock, usually by “cracking” large molecules into small

ones, e.g., catalytic cracking and hydrocracking.

10.3.1 removal of Sulfur Compounds

The sulfur compounds of most concern are hydrogen sulde, mercaptans,

and free sulfur. Sulfur may account for up to about 5% by mass in crude

oil. During combustion, sulfur is oxidized to SO

and then to acids, which

are corrosive. Therefore, in low concentrations, hydrogen sulde is easily

n-C9

n-C10

n-C11

n-C12

n-C13

n-C14

n-C15

n-C16

Figure 10.1

Gas chromatograph of the composition of jet fuel (Jet-A/JP-8/JP-5).

Alternative Fuels 449

removed by washing with a strong alkali; when the concentration is high,

its removal is best effected by the Girbotol process in which the hydrogen

sulde is absorbed in liquid diethanolamine.

Mercaptans are undesirable because they are corrosive and have an offen-

sive odor. Mercaptans may be removed by washing with caustic soda or

caustic potash, but usually it is sufcient to convert them into sulfur com-

pounds of a harmless nature that can remain in the fuel. Sometimes, a hydro-

gen treatment is employed whereby the sulfur compounds are removed by

reaction with hydrogen in the presence of a catalyst. The hydrogen sulde

formed is then either removed or absorbed. Although the elimination of

sulfur is generally desirable, some sulfur compounds provide boundary

lubricity, thus their complete removal could lead to problems of fuel-pump

seizure.

The corrosion tendency of sulfur compounds and free sulfur is controlled

by requiring the fuel to pass a copper-strip corrosion test. This consists of

a visual estimation of the change in color of a copper strip that has been

immersed for a prescribed time in the test fuel, which is maintained at a

specied temperature.

Clay treatment is used to remove surfactants and improve color and stabil-

ity of fuel. Surfactants can degrade the ability of lter/separators to remove

water from fuel, and free water in jet fuel can freeze at high altitudes. In this

treatment, fuel is heated and then brought into contact with clay contained

in a canister or a cloth bag. After vigorous mixing, the spent clay is removed

by ltration.

10.3.2 Contaminants

In addition to sulfur and sulfur compounds, distillate fuels contain impuri-

ties, such as water, gum, and trace quantities of metal particles. Residual

and crude oils contain larger quantities of these, as well as some metallic

compounds that oxidize to form ash.

10.3.2.1 Asphaltenes

Asphaltenes are high-boiling-point hydrocarbons that are found in crude

oils and their residual products. They encourage the formation of low-

temperature sludge that can block fuel-ltration equipment.

10.3.2.2 Gum

All practical fuels contain minute quantities of inorganic elements, such as

sulfur, nitrogen, oxygen, and various metals. Under the action of tempera-

ture, light, and the catalytic effect of suspended metal particles, fuels can

react with atmospheric and/or dissolved oxygen to form gums. Such prod-

ucts may clog fuel lters and deposit on the surfaces of aircraft fuel systems