steam generator performance

8/3/2019 Steam Generator Performance

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UnderstandSteam GeneratorPerformance

The key

performance

variables are

excess air, fuel

type, exit gas

temperature, load,

and emissions.

V. Ganapathy,

ABCO Industries

Several variables affect theplant engineers plan their operation better.This article discusses the effectsof such variables as excess air,fuel type, exit gas temperature,load, and emissions ongenerator design and operation.It also discusses some of the

potential benefits ofcustomized steam generatorsover standard, prepackageddesigns, which often compro-mise on overall performance.The focus of the article is limit-ed to gaseous and oil fuels.

FigureBOILER EFFICIENCY

The single most important variable from aperformance standpoint is the steamgenerator efficiency. This is particularly

true for base-load steam generators thatwill operate most of the time (unlike astandby boiler, which operates for only afew hours per year).During the design stage, the consultant orthe end user specifies a certain efficiency.Efficiency is primarily affected by the fuelcomposition, unburned carbon losses,excess air, exit gas temperature, and thet e of fuel (Table 1).

Fuel composition

The fuel composition is important, asit affects the flue gas composition, whichin turn affects the various heat losses.While variations may not be significantbetween typical natural gases, differencesbetween a low-Btu and a high-Btu gas domatter.

1. Large pack aged steam generator.

increase the fuel moisture loss. Similarly,the percentages of hydrogen and carbon inoil fuels affect the fuel moisture loss and

hence the efficiency, as shown in Table 1.Unburned carbon losses

The various boiler heat losses are evalu-

ated at the design stage using the AmericanSociety of Mechanical Engineers' Power TestCode heat-loss method, ASME PTC 4.1.

One of the losses impacted by the com-bustion process is the unburned carbon

42 DECEMBER 1994 CHEMICAL ENGINEERING PROGRESS


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loss. Carbon in the fuel is converted to

carbon monoxide instead of carbon

dioxide, which results in lower carbon

utilization. With gaseous fuels this

may be insignificant. However, with

fuel oils, the amount of CO formed can

be very high - on the order of severalhundred ppm.

The type of burner used, theamount of excess air, turbulence inthe combustion zone, and the type offurnace construction (that is, whetherit is a membrane wall or tangent tubedesign) influence this loss. Leakage ofcombustion products from the furnaceto the convection section via a tangenttube partition wall contributes a greatdeal to CO formation, because thecombustion products do not have theresidence time in the furnace tocomplete combustion before enteringthe convection section. A highexcess-

air operation may be required tominimize this loss; however, thisdecreases the efficiency due toincreased heat losses, as shown in

Table 1.

The loss L(in Btu/lb) due to CO

formation is given by:

L = 10,160 C [CO/(CO + CO2)]

where CO and CO2 are the volumepercentages in the flue gas and C isthe weight fraction of carbon in the

fuel.

Excess a i r

Excess air affects efficiency signifi-

cantly, as indicated in Table l.The choice of how much excess air

to use depends on the type of fuelused and the desired levels of NOx andCO emissions, as well as the degree offlue gas recirculation (FGR). Burnersuppliers often recommend theamount of excess air after reviewing

the emission levels to be guaranteed,the fuel analysis, and the furnacedimensions. A high excess air (on theorder of 10-15%) is often suggestedeven for natural gas fuels. This isbecause FGR is used to limit NO,

which in turn affects the burnout ofCO; higher excess air helps tocomplete combustion. Figure 2 showsthe typical relationship between excess

air and emissions.

CHEMICAL ENGINEERING PROGRESS DECEMBER 1994 43


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Exit gas temperature

The lower the exit gas temperature, the

higher the boiler efficiency. A rule of thumbis that every 40F difference is equivalent to a

1 % change in efficiency. However, if thetemperature of the feed water entering theeconomizer is higher, then the stacktemperature will also be higher. Otherwise, avery large economizer may be required tomaintain the same exit gas temperaturecompared to a low feed water temperaturecase.One factor influencing the exit gastemperature is the sulfuric acid dew point.When fuels containing sulfur are fired, SO 2 isformed, and some of it (1-5%) is converted toSO3, particularly if vanadium is present in theoil ash, which acts as a catalyst. When the acid

vapor gets cooled by the feed water,condensation may occur if the temper ature ofthe tube surface is at or below the acid dewpoint. Dew point is a function of the partialpressure of the acid vapor and water vapor inthe flue gases. Table 2 shows a fewcorrelations for acid vapors (1, 4, 5).There is a misconception, even amongexperienced engineers, that condensation inthe economizer can be avoided bymaintaining the exit gas temperature highenough. When an economizer is used as theheat recovery equipment, the cold end

temperature is mainly a function of the feedwater temperature entering the boiler and thegas temperature has little effect on it. This isdue to the high tube-side heat-transfercoefficient. Table 3 shows a simplecalculation where the exit gas temperaturevaries by as much as

44 DECEMBER 1994 CHEMICAL ENGINEERING PROGRESS

For each fuel there is range of excess airthat achieves the desired CO and NO x levels.Higher molecular weight hydrocarbons have ahigher flame temperature, which produces

higher NOx, which in turn requires a higherdegree of FGR to limit it, which in turn mayrequire higher excess air, depending on theCO levels to be guaranteed. The experienceof burner suppliers with units burning similarfuels and having similar emissions oftendetermines this parameter.


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400F, while the economizer tube walltemperature varies by only a fewdegrees (/, 2, 6).However, it is not necessary to havethe feed water temperature at or above

the acid dew point to minimize corro-sion problems. While this is a su re wayto prevent acid condensation, researchhas shown that corrosion i s significantat 50-100F below the acid dew point,as illustrated in Figure 3 (/, 6). Hence,one need not specify a high feed watertemperature, which results in a lowerefficiency. If the acid dew point is,say, 275F, a 230-250F feed watertemperature is a good compromise. Anexit gas temperature of 300-320F canbe achieved with moderate costs.Air heaters are often avoided as back-

end heat-recovery equ ipment. This isbecause they contribute to high ercombustion temperature and henceNOx, which calls for higher FGR rates,which in turn results in a higher gaspressure drop through the boiler or alarger boiler or both. Also, the gaspressure drop through an air heater ismuch higher, by 2-3 in. w.c., which isa continuous loss of energy.When an air heater is used, it is usu allyone of two types - the tubular orrecuperative, or the regenerative orrotary air heater. Rotary air heatershave the additional problem of leakage

from the air to the gas side, whichaffects the fan size and air heater per-formance. An advantage of air heaters,though, is that they may be more com-pact than tubular air heaters. Airheaters are primarily recommendedwhen difficult fuels, such as solid fuels

and low-Btu gaseous fuels, are fired.

F lue gas quant i t y

Using higher excess air and FGRrates for the same boiler duty increasesthe flue gas quantity to be handled bythe boiler. This naturally results in a

larger boiler or, if dimensions arelimited because of shippingrestrictions (which is often the case), ahigher gas pressure drop is incurred inthe convection section andeconomizer. Table 4 shows the fluegas quantity produced with different

excess air and FGR factors.

This is one of the reasons why it isoften beneficial to go with a customdesigned steam generator - tube spac-ings, tube height, and the number oftube sections can be varied tominimize gas pressure drop.Unfortunately, packaged boilers areoften treated as predesigned or off-the-shelf items. Some consultants evensuggest model numbers whiledeveloping specifications. Thispractice should be avoided. Otherwise

you could be purchasing a design thatwas developed several decades ago,when emissions were not a concernand FGR was not considered whilesizing the convection section andeconomizer. These steam generatorswere designed with skimpy furnacesand low excess air factors and withoutany FGR. Hence, even if the steamparameters may be the same, the flue

gas flow through the unit

can be nearly 30-40% more, resultingin higher gas pressure drops, higherexit gas temperatures, and thereforelower efficiency and much higheroperating costs. Engineers shouldunderstand these aspects and opt forcustom designed units, which canincorporate several design features tominimize operating costs and improveefficiency.As an example, if 130,000 lb/h of fluegases have to be forced through an

additional 3 in. w.c. in the bo ilerbecause a standard rather than customdesign is used, the additional fanpower consumption is 14.5 kW, basedon a 70F air temperature and a fanefficiency of 70%. Assuming that theboiler operates for 8,000 h/yr and thatelectricity costs 1 /kWh, theadditional cost is $11,600/yr.Capitalizing this cost over the lifetime

of the boiler



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E N E R G Y T R A N S F E R / C O N V E R S I O N

shows that when one considers boththe operating and the initial costs, itpays to select a custom designed unit,since the additional capital costs for acustom-designed system is generallyonly about $20,000 to $30,000, and insome cases is virtually nil.

S U P E R H E A T E R D E S I G N

It is very important to know wherethe steam generated by the bo iler isused. Steam turbines require a highsteam purity, which calls for gooddrum internals such as chevrons andcyclones. If saturated steam isgenerated, simple mist eliminators maybe adequate.Another aspect to be determined is therange of load over which the steamtemperature has to be maintained. A

wide load range calls for a large and,therefore, expensive superheater. Con-sultants must discuss with clients andturbine suppliers before specifying thisrequirement. While 70-100% loadrange of superheat temperature contro lis common, some designers unknow-ingly specify steam temperature controlfrom 40% to 100% load, whichcomplicates the superheater design.The superheater is the equipment mostsignificantly affected by parameterssuch as excess air, flue gas recir-culation, and furnace sizing. A larger

furnace results in a lower exit gas tem-perature, which increases the super-heater size due to the lower log meantemperature difference available. Ahigh FGR rate increases the size of thesuperheater and the gas pressure drop.Typically, the steam temperature ismaintained at 70% to 100% load. Withconvective type superheaters (Figure4), this means that the steam tempera-ture will be higher at higher loads.Interstage attemperation should beincorporated to control the steam tem-

perature at higher loads.Radiant superheaters, which are locatedin the furnace zone or exposed todirect flame radiation, generally operateat higher tube wall temperatures. Thus,unless these units are very carefullydesigned, failures are more likely.Radiant superheaters behave differentlythan convective superheaters -

at lower loads, they absorb moreenergy due to radiation and thus havehigher steam temperatures.The spraying of feed water into thesteam for steam temperature controlcan increase the solids content o f the

L o w - l o a d o p e r a t i o n

There are also a few issues of con-

cern at low loads, particularly withsuperheater and fan operation.

The number of streams (the areathrough which steam flows in a super

Figure 4. Superheater for steam generator.

steam. Thus, the feed water shouldhave the same amount of solids as thefinal steam - in the ppb range.Demineralized water is preferred forsuch applications. If demineralizedwater is not available, saturated steammay be condensed in a heat exchangerand sprayed into steam, as shown inFigure 5a and 5b.

heater) has to be chosen so that a good

distribution occurs even when the boil-er operates at the lowest load. Someconsultants specify turndown of 1:8 oreven 1:10. From a practical point ofview, a turndown this high is not rec-ommended.

The real problem is in the ability ofthe superheater and f an to handle such

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low-load conditions. If the steampressure drop is, say, 50 psi at 100%load, it will be 3 psi at 25% load. Atlower loads, it is difficult to ensurethat the flow distribution will be

uniform through all the tubes. Onehas to be also concerned aboutreverse flows, which can result inoverheating of some tubes andpossibly failure.The author recommends a load rangeof 50% to 100%, not 10% to 100%,since performance is difficult topredict at low gas and steamvelocities.Another prob lem with low-loadoperation is the fan performance. Ifthe fan is selected with high marginson flow and head, then at low loads,the operating point may fall below the

capacity of the fan even at the lowestvane opening position (Figure 6).This may cause problems with fanoperation, such as vibrations,instability, and noise. This is likely inpackaged boilers, which typicallyhave one forced draft fan. If two fanseach having half the capacity are usedinstead, then a higher turndown isfeasible. Also, at low flows, the fanoperating point can drift into theunstable operating regimes of the fancurve.

Using a high margin for the fan flow

and head should be avoided. The

author suggests 10% on flow and 20%

on head.

LOAD VS.PERFORMANCE

Figure 7 shows the performance of aboiler at different loads. The effi-ciency peaks at a certain load andthen drops off. This is expected, asthe nature of the two important losses,namely radiation and flue gas heatlosses, differ. At higher loads, theradiation loss will be lower and the

heat losses due to the flue gases willbe higher; the opposite is true atlower loads. The combination of theselosses results in a peak efficiency, atsome load between 0% and 100%.

The exit gas temperature drops off

with load. An economizer acts as a

heat sink, which limits the gas

temperature so that gas is not cooled

to dew point levels.

The approach point, or the feedwater temperature leaving the econo-

mizer, decreases when load decreases(unlike in a gas turbine heat -recoverysteam generator, or HRSG). Hence,steaming is not a problem at low

loads.

CUSTOMIZED DESIGNS Asmentioned earlier, adopting a standarddesign developed decades ago topresent-day operating conditions with

high excess air and FGR

rates results in a compromise on per-formance and operating costs.

Customized designs can overcome theseconcerns. Following are some of theaspects reviewed in customized designs.

1. Furnace design, which considers

the excess air and F GR rates and

flame dimensions for each fuel, after

discussions with the burner supplier

so that the flame is contained entirely

within the furnace.



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2. Convection section design, whichcan have longer tubes, wider tubespacing, and more tube sections toreduce gas velocity and hence pres -sure dro to acce table levels.

3. The possible use of extendedsurfaces in the convection section ifclean fuels are fired. Extended sur-faces can result in compact designs,lower as ressure dro , and lower

exit gas temperatures from the con-vection section (1).4. Superheater location and whether itis in the appropriate gas temperaturezone in the convection section tooperate safely over a wide load range.

If the steam temperature is lowenough, the superheater could even belocated downstream of the convectionsection and ahead of the economizer.

5. Horizontal or verticaleconomizers to match the layoutrequirements.

To receive a free copy of t his article,send in the Reader Inquiry card in t his

issue with the No. 180 circled.

48 DECEMBER 1994 CHEMICAL ENGINEERING

steam generator performance

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