Backend corrosion in bagasse-coal fired boilers with … CORROSION IN BAGASSE – COAL FIRED BOILERS WITH PARTICULAR REFERENCE TO CO-GENERATION MAGASINER N Magasiner Technology, 6

BACKEND CORROSION IN BAGASSE – COAL FIRED BOILERS

WITH PARTICULAR REFERENCE TO CO-GENERATION

MAGASINER N

Magasiner Technology, 6 La Camargue, 263 Beach Road, Sea Point, 8005, South Africa

[email protected]

Abstract

Low temperature corrosion is experienced in an operating boiler when metal temperatures

drop below the acid dew point (ADP) of the flue gas. H2SO4 and HCl are the acids which

contribute most aggressively to corrosion. Both these acids can be produced when burning

bagasse and trash. The H2SO4 ADP is largely dependent on the sulphur content of the fuel

which mostly oxidises to SO2 during the combustion process and on the proportion of SO2

that converts to SO3. SO3 in turn converts to H2SO4 as the gas cools from about 400°C down

to about 175°C.

Chlorine in the fuel converts to HCl during the combustion process. The dew point of HCl is

lower than that of H2SO4. Although bagasse does not normally contain sufficient Cl for HCl

to become a major contributor to corrosion, recent studies in Denmark and Sweden show that

even small quantities of chlorine can be aggressive at higher temperatures if zinc and calcium

are present with high water vapour contents. Trash, when burned as a side stream, can provide

sufficient quantities of these salts to cause a problem.

The H2SO4 and HCl ADPs are dependent on the partial pressures of the water vapour, SO3

and HCl in the flue gas. Graphs are provided to enable the boiler operator to determine the

concentrations by volume of these gasses and hence their partial pressures. Formulae based on

the partial pressures are provided to determine dew points when burning bagasse and other

wet biomass fuels, such as wet woodwaste as well as coal.

Burning coal with bagasse aggravates the backend corrosion problem. Coal normally has a

much higher sulphur content than bagasse but a lower moisture content. If burned on its own

it may have a lower H2SO4 ADP than bagasse because of its lower moisture content. When

coal is combined with bagasse the ADP is elevated, largely due to the much higher moisture

content of the combined flue gases. This can have serious long term corrosion implications for

the back end. The paper describes how to determine the ADP when dual firing.

With co-generation boilers, as pressure rises, a single pass air heater placed upstream of a

multi-bank extended surface carbon steel economiser provides the best security from a

corrosion point of view. At higher pressures the case for a steam heated air heater in place of a

gas/air air heater becomes stronger. Graphs are provided to show how efficiency can be

improved with the addition of extra economiser heating surface and by lowering the feed

water temperature. Feed water heaters should be used to preheat water fed to economisers. Air

bypasses should, when necessary, be used around air heaters to reduce the air’s cooling effect.

By being aware of the ADP of the fuels being burned the operator can adjust the feed water

temperature and/or the air heater bypass to maximise plant efficiency without the risk of

corrosion.

Magasiner N Proc S Afr Sug Technol Ass (2010) 83: 422 - 443

422

An abstract from a Swedish publication on high temperature corrosion is included in

Appendix 4 to make the corrosion picture more complete.

Keywords: boilers, bagasse, corrosion, dew point, heat recovery, co-generation

Introduction

Controlling combustion efficiency and stability, erosion of convection heating surfaces and

backend corrosion are three of the most important design issues that have to be addressed

when designing a bagasse fired boiler.

Combustion efficiency and stability are determined by the design of the fuel feeding system

and grate, the grate rating, the combustion air temperature and the ratio of primary to overfire

air as well as the size and position of the overfire air nozzles. Erosion of convection heating

surfaces is largely a function of dust burden, gas velocities and heating surface geometry, with

the physical and chemical characteristics of the dust playing a prominent role as well. In most

cases, cost effective solutions to the combustion and erosion problems can be arrived at from

a combination of past experience and computer modelling. Sophisticated computerised fluid

dynamic (CFD) modelling programs have been developed that not only plot the chemical

species of the flue gases flowing through the boiler passes, but also establish gas velocities

with some degree of accuracy. Figure 1 shows a typical gas velocity and CO profile printout

for a 225 t/h single pass bi-drum boiler fitted with a single pass air heater and three banks of

extended heating surface economiser.

Figure 1: CFD study of a 225 t/h boiler equipped with a single pass air heater and three banks of extended surface economiser. The LH picture shows the velocity profile (m/s). The RH picture shows the CO profile (ppm CO). (Ch

27, Rein (2007); Courtesy Sugar Research Inst, Mackay, Australia).


423

This paper deals with the physics and chemistry of the remaining problem; i.e. backend

corrosion and the tools available to the designer and boiler operator to control corrosion.

Graphs and equations are included that apply to typical cane sugar industry operating

conditions. The graphs and equations can also be used to evaluate the potential for backend

corrosion to occur when burning other biomass fuels, such as woodwaste, which have similar

moisture and ash contents. Also included is a graph showing how, when mixed firing, the

H2SO4 ADP varies with the load carried on coal, the amount of sulphur in the fuels and the

amount of SO2 converted to SO3. Graphs are provided to show how final gas temperature

varies with economiser heating surface and to what extent efficiency can be improved by

reducing feed water temperature when an economiser is the last heat recovery surface in the

chain.

Backend corrosion physics and chemistry

A plot of the water vapour dew point for a range of bagasse compositions is shown in Figure

2. The concentration by volume of moisture in the flue gas when burning 46% moisture

bagasse having an ash content of 2% will be just over 26%. For 56% moisture bagasse with

an 8% ash content the moisture in the flue gas will be a little under 34%. These moisture

contents are about 3.5 to 5.0 times higher than those produced when burning coal.

Backend corrosion in bagasse fired boilers is caused by sulphuric and to a far lesser extent

hydrochloric acids condensing onto

heating surfaces that operate below their

respective ADPs. These hot acids are

concentrated and highly corrosive.

Corrosion rates are mainly a function of

the concentrations of sulphur and chlorine

in the fuels and the moisture

concentrations and excess air levels in the

flue gas.

The H2SO4 and HCl dew points are a

function of the partial pressures of the SO3,

HCl and water vapour in the flue gas. A

number of formulae are available to

determine the H2SO4 ADP, two of which

are used extensively. These were derived

by Verhoff and Banchero (1974) (equation

1; Appendix 1) and Okkes and Badger

(1987) (equation 2; Appendix 1).

There do not appear to be any definitive numbers for the conversion rate of SO2 to SO3 for

bagasse. The conversion rate for woodwaste appears to be about 2%. As wet woodwaste has

very similar combustion characteristics to bagasse it would appear that this figure may also

apply to bagasse. If so, the two formulae referred to above, within the range 1-3%, agree

closely.

Figure 2: Water dew point as a function of moisture in flue gas.

Water Dew Point

65

66

67

68

69

70

71

72

73

26 28 30 32 34

Moisture Concentration in Flue Gas (vol %)

Water Dew Point oC


424

Figure 3 plots the H2SO4 ADPs as

calculated by the Verhoff and Banchero

(1974) and the Okkes and Badger (1987)

methods.

To be able to use the above formulae one

must know the concentrations by volume of

water and SO2 vapour in the flue gas. These

figures are normally calculated from the

fuel’s ultimate analysis and the expected

excess O2 concentration. Figures 4 and 5

shortcut this procedure. Given fuel moisture

and ash content on a % by mass ‘as fired’

basis and sulphur in the fuel on a by mass

dry ash free % (DAF) basis, Figure 4 can be

used to determine the concentration of water

vapour and Figure 5 the concentration of

SO2 in the flue gas. Both these

concentrations are reported as percentages.

They can be converted to partial pressures

by multiplying them by 1.01325/100 to

arrive at the partial pressures at sea level,

0°C. The partial pressures must be corrected

for altitude and also take the suction in the

gas ducting into account. A suction of 2500

Pa will bring the ADP down by about 0.5°C. At higher altitudes (lower atmospheric pressure)

the dew points are lower.

Oxidation of S to SO2 takes place in the furnace at high temperatures. SO2 partially converts

Flue Gas Moisture - Bagasse

22

24

26

28

30

32

34

36

46 48 50 52 54 56

Fuel Moisture (mass %)

Concentration of H2O in Flue Gas (vol %)

2 % ash

8 % ash

5 % ash

3 % O2

5 % O2

Figure 4: Concentration of Moisture in Flue Gas as a function of Fuel Moisture, Ash Content and O2

Figure 5: Concentration of SO2 in Flue Gas as a function of Fuel Moisture, Sulphur (DAF) and O2

Flue Gas SO2 - Bagasse

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

0.020

46 48 50 52 54 56


Concentration of SO2 in Flue Gas (vol %)

0,200 S DAF

0,100 S DAF

0,050 S DAF

0,025 S DAF

3% O2

5% O

2

Figure 3: Comparison of Verhoff and Banchero (1974) and Okkes and Badger (1987) methods of determining

Acid Dew Points

Sulphuric Acid Dew Point

52 % Moist Fuel, 2 % Ash, 3 % O2

and 0.025 % S (DAF)

80

85

90

95

100

105

110

115

120

125

130

0 1 2 3 4 5

% SO2 Converted to SO

3

Acid Dew Point oC

V + B Method

O + B Method


425

to SO3 in the furnace, superheater and

convection passes. Catalysts can enhance the

reaction. It is well known that when burning

heavy fuels oils, Fe and V act as catalysts in

the superheater and convection passes.

The conversion of SO3 to H2SO4 starts at over

400°C and is completed by the time the gas

temperature has dropped to just below 176°C.

Table I schedules the percentage of SO3 that

converts to H2SO4 at a given temperature.

Most, if not all, of the chlorides in cane are leached out in the milling process. Trash can,

however, contain chlorine. Where trash is burned as a fuel supplement, hydrochloric acid

corrosion may become a problem. Figure 6 plots the dew point of hydrochloric acid as a

function of its concentration in the flue gas. Hydrochloric acid is formed when chlorine

combines with water vapour in the boiler. Figure 6 is derived from equation 3 (Appendix 1)

developed by Yen-Hsiung Kiang (1981). The HCl reaction takes the reversible form:

2H2O + Cl2 ↔ 4HCl + O2

HCl can also be formed by sulphuric acid reacting with salt deposits in the colder passes of

the boiler. The combination of HCl and H2SO4 is particularly aggressive.

The potential risk to boiler heating surfaces

of HCl condensing under normal operating

conditions is small as these surfaces usually

operate at temperatures well above 80°C.

Ducting, dust collectors and stacks, if not

properly protected, may under cold windy

conditions operate below the HCl ADP and

hence may be at risk.

Jansen et al. (2001) point to ZnCl2 and

CaCl2 initiating HCl corrosion in biomass

fired boilers in Denmark at much higher

temperatures than those predicted by the

Yen-Hsiung Kiang (1981) dew point

equation. Recent research carried out by

Lindau and Goldschmidt (2008) in Sweden

postulates that, for high moisture content

fuels, such as woodwaste, chloride

corrosion occurs at higher temperatures

because highly soluble ZnCl2 and CaCl2

dusts pick up water vapour from the

exhaust gas to form a solution. Solutions

have lower vapour pressures than pure

water and hence boil at higher temperatures. Sugar engineers will be familiar with this as the

boiling point elevation that occurs in an evaporator. Lindau and Goldschmidt (2008) refer to

Table 1 SO3 Conversion to H2SO4 at Various Gas Temperatures

Gas Temperature (°C) SO3 Converted to H2SO4 (%)

400 3.85

371 14.30

315 47.50

287 70.54

260 87.50

204 98.56

176 99.84

Dr-Ing Dissertation; Maria Pla Perujo, Technischen Universität, Berlin, 22 Nov 2004.

Figure 6: Hydrochloric Acid Dew Point as a function of the concentration of HCl and moisture in Flue Gas.

Hydrochloric Acid Dew Point

60

62

64

66

68

70

72

74

76

0 0.1 0.2 0.3 0.4 0.5

Concentration of HCl in Flue Gas (vol %)

Acid Dew Point oC

26 % moist

29 % moist

34 % moist


426

the phenomenon as the DRH (deliquescent relative humidity). This is the ratio of the partial

pressure of a salt solution to the partial pressure of pure water at a given temperature. The

DRH is always less than one. The lower it is the greater is the solubility of the salt.

Figure 7, taken from Lindau and Goldschmidt (2008), plots the DRH for ZnCl2 and CaCl2 and

the RH of exhaust gases having moisture contents of 15 and 25% against temperature. The

curves, when extrapolated, show that the dew point of a ZnCl2 solution will be about 128°C if

the RH of the gas is 15% and about 140°C if it is 25%. For a CaCl2 solution these figures are

about 95 and 110°C respectively. These authors go on to suggest from observations made on a

number of low pressure hot water woodfired boilers that corrosion is initiated in the presence

of these salts when the moisture content of the flue gas exceeds 22%. As flue gas moisture

when firing bagasse is between 26 and 34%, bagasse fired boilers are potentially at risk.

Burning coal, which can have a have a relatively high chlorine content, together with bagasse

may aggravate the problem.

As it is difficult to predict the HCl

concentration in the flue gas and as on-line

HCl corrosion does not usually occur

because the HCl ADP is much lower than

the H2SO4 ADP, the balance of this paper

deals largely with H2SO4 corrosion which,

in any event, is the dominant corrosion

mechanism. DRH corrosion can only be

dealt with on a case-by-case basis.

Coal can have a sulphur content about ten

times higher than that of bagasse but it

generates only about one third to half as

much flue gas moisture. When burning the

fuels together the high sulphur content of

the coal in combination with the high

moisture content of the bagasse elevates the

H2SO4 ADP. The ADP of coal is usually

higher than that of bagasse but it can be

lower if the sulphur content of the bagasse

is more than about 20 % that of the coal.

When the two fuels are burned together the

ADP is usually higher than it would be for

either of them burned singly.

The concentration of moisture in the flue gas when burning coal can be obtained from Figure

8. The graph takes cognisance of the relatively large contribution made by the fuel’s hydrogen

content. This correction is incorporated automatically in the bagasse graphs in Figures 4 and

5.

Figure 9 plots the concentration of SO2 generated when burning coal as a function of the total

Figure 7. DRH for CaCl2 and ZnCl2 blue curve = RH of flue gas with 15 % H2O; orange curve = RH of flue gas with 25 % H2O – Courtesy Lindau and Goldschmidt

Relative Humidity of Water Vapour

and DRH of ZnCl2 and CaCl2 vs Temperature

0.0

0.1

0.2

0.3

0.4

0.5

0.6

50 70 90 110 130 150

Temperature OC

RH and DRH

RH 25% H2O

RH 15% H2O

DRH ZnCl2

DRH CaCl2


427

concentration of moisture (free, inherent and that arising from the oxidation of H2 to H2O).

Whereas fuel moisture is the input to Figure 5, the moisture concentration read off Figure 8 is

the input to Figure 9.

As with bagasse there do not appear to be reliable figures for the conversion rate of SO2 to

SO3 for coal burned on a spreader stoker. Srivastava et al. (2002) suggest that for pulverised

coal fired boilers about 0.1 to 0,65% of the SO2 generated is converted to SO3. The

conversion rate is heavily dependent on the amount of excess air used and, as mentioned

above, is also enhanced by the catalytic action of Fe and V in the superheater and convection

passes.

Figure 10 shows how, when mixed firing, H2SO4 ADP varies as the percentage of load carried

on coal increases. The curves are based on a 52% moisture, 2% ash bagasse having a sulphur

content on a DAF basis of 0.05% (0.023% S ‘as fired’). The coal analysis is taken from

Magasiner (2001), Table 2, with sulphur content varying from 0.3 to 2.0% whilst keeping the

moisture and ash contents constant. For bagasse the SO2 to SO3 conversion rate is 2,0 % and

for coal it is 0,5%.. ‘As fired’ sulphur levels in bagasse are usually around 0.01 to 0.04%. In

Florida, where there is a high concentration of H2S in the ground water, the S in bagasse can

be over 0.1%.

For coal with sulphur levels higher than about 0,7 %, as load increases, the ADP usually

rises. For these higher sulphur contents the ADP reaches a maximum when the load carried on

coal is about 80 to 90% of the total load on the boiler, after which it drops rapidly down to the

ADP of the coal itself.

In the past the author has argued against mixed firing of bagasse and coal in order to minimise

the risk of forming unmanageable clinkers on the grate. It is clear from Figure 10 that mixed

firing should be carried out with due regard to the sulphur levels in the fuels as well.

Figure 8: Concentration of moisture in flue gas as a function of fuel moisture, H2 and O2.

Flue Gas Moisture - Coal

6

7

8

9

10

11

12

13

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16


Concentration of H2O in Flue Gas (vol %)

6% H2

5% H2

4% H2

3% H2

3% O2

5% O

2

Figure 9: Concentration of SO2 in flue gas as a function of moisture concentration (including H2 generated

moisture), S and O2.

Flue Gas SO2 - Coal

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Moisture Concentration in Flue Gas (vol %)

Concentration of SO2 in Flue Gas (vol %)

2% S

1% S

3% O2

5% O2


428

A program for calculating the ADP when

mixed firing is included in Appendix 2.

Some of the sulphur and chlorine in the

fuel can be bound with the ash and fly ash

during the combustion process. The above

calculations are based on the conservative

assumption that all the sulphur and

chlorine in the fuel reports to the gas

phase.

A bagasse ‘as fired’ sulphur content of

0.023% (DAF 0.05%) may not seem much

when compared with the sulphur contents

of fossil fuels such as coal and oil. But, if

dew point conditions occur in an air heater,

metal loss of the affected tubes can vary

from 20 to 85%, or more, in five years.

Metal temperatures

Low temperature corrosion takes place

when metal surface temperatures drop

below the ADP. These surfaces include the

economiser, air heater, exhaust gas

ducting, dust collecting equipment and chimney. All these surfaces are exposed to flue gas on

one side and either water or air on the other. The boiler pressure parts of hot water and steam

boilers operating at less than 3 bar may also be subject to corrosion.

The metal temperature is dependent on the temperature

of the fluids, the heat transfer coefficients on either

side of the metal and to a far lesser degree the heat

transfer coefficient of the metal itself. Figure 11

illustrates the temperature gradient through a metal

barrier such as an air heater or economiser tube or gas

ducting.

For practical purposes it is sufficiently accurate to

assume there is no temperature gradient through an air

heater’s tube wall. It is normally less than 1.5°C. The

average metal temperature can be calculated from the

equation:

Heat transferred from gas side = Heat transferred to fluid side 1

i.e. kg·(Tg -Tm) = ka·(Tm -Ta) 2

Figure 11: Temperature gradient through a metal barrier such as an air heater or economiser tube or a gas

duct.

Gas side boundary layer

Fluid side boundary layer

Scale

Figure 10: Chart showing how, when mixed firing, the sulphuric acid dew point varies as the proportion of load

carried on coal increases.

110

115

120

125

130

135

140

145

150

0 20 40 60 80 100

Acid Dew Point oC

Coal Firing %

Bagasse/Coal Fired H2SO4 Dew Point Verhoff and Banchero Method

% S in Coal "as fired"

0,30 %1,00 %1,50 %

Coal SO2 to SO3Conversion

0,5 %1,0 %2,0 %


429

and hence Tm = (Tg·kg + Ta·ka) 3

(ka + kg)

The overall heat transfer coefficient can be calculated from the relationship:

1/koverall = 1/kg + 1/ka 4

where:

Ka is the air side convection heat transfer coefficient W/m2·°C

kg is the gas side convection heat transfer coefficient W/m2·°C

koverall is the overall heat transfer coefficient W/m2·°C

Tm is the average metal temperature °C

Ta is the air temperature °C

Tg is the gas temperature °C

Air heaters can be designed to have gas flowing through and air over the tubes or vice versa.

To minimise erosion, cane sugar boiler air heaters usually have the gas flowing through the

tubes.

In well designed air heaters the metal temperature is a little below or about halfway between

the gas and air temperatures. The heat transfer coefficients on both the air and gas sides of an

air heater range between 45 and 65 W/m2·°C. Because the outside area of a tube is larger than

its inside area, for these figures to be used in equation 2, they need to be referred to the same

side of the tube.

To achieve similar coefficients on both sides and hence a metal temperature about midway

between the gas and air temperatures, gas velocities of about 20 to 25 m/s and air velocities of

about 4 to 5 m/s are required for a diagonally pitched 63.5 mm diameter tube array. While

these high gas velocities will lead to severe erosion if the gas flows over the tubes, they are

acceptable for gas flowing through a tube. To avoid localised erosion if the gas inlet ducting

design leads to dust channelling, it is sometimes advisable to insert replaceable hardened steel

or ceramic inserts into the mouths of the tubes. These inserts measure 1.5 to 3 times the tube

diameter in length.

For a plain tube economiser the gas side heat transfer coefficient is about 1.5 times higher

than it is for an air heater. On the water side the heat transfer coefficient is in the region of

about 15 000 W/m2·°C. Economiser average metal temperatures are therefore close to the

water temperature (usually less than 1°C higher than the water temperature at the cold end) so

the best way of controlling the metal temperature and hence corrosion is to pre-heat the feed

water. The temperature gradient across the tube is usually less than 1°C.

In the author’s experience over the past two decades mild steel finned tube economisers

outperform plain tube economisers from an overall cost, erosion and corrosion point of view.

Acid condensate on metal surfaces when operating below the dew point acts like flypaper

trapping dust and char. The gas side of cast iron finned tube economisers which were used

extensively until the 1980s and which are more corrosion resistant than finned mild steel units


430

often choked because they were fed with water at 80 to 105°C; i.e. at temperatures which

were often below the dew point; hence the need for feedwater heaters.

Heat recovery plant arrangements

Conventional mills

From the late 1950s most new boilers installed in the South African cane sugar industry were

designed to operate at about 30 bar (g). This limit was set to obviate the need for sophisticated

boiler water treatment regimes and water quality controls. Now, a typical 30 bar boiler

installed in a conventional thermally balanced cane sugar factory will include a water cooled

furnace, a superheater, a convection bank and an air heater. The air heater can be arranged

either as a parallel or contra flow heat exchanger.

The flue gas will leave the convection bank at between 350 and 420°C (for higher

temperatures ducting must be made of heat

resistant steels). Typically the temperature

profile across the air heater will be as

shown in Figure 12. From a corrosion point

of view it makes little difference when

steaming at MCR whether a contra flow or

parallel flow air heater is installed. In both

cases the minimum metal temperature will

be above the H2SO4 ADP. As load falls,

both parallel and contra flow arrangements

will be more susceptible to corrosion, with

the parallel flow unit having more leeway

than the contra flow unit. Parallel flow air

heaters are, of course, more expensive

because of the larger surface area they

require. The example in Figure 12 is 67%

larger.

Where extra thermal energy is required for the production of refined sugar or by-products, or

when power is needed for irrigation during the crop or to supply a village located on mill

property, the unit may often be equipped with an economiser to improve its efficiency.

Economisers are also required for co-generation facilities. The question of where to locate the

economiser – before or after the air heater is – discussed later.

Cogeneration facilities

Three parameters largely determine the efficiency of a co-generation cycle, which is in

essence a regenerative Rankine cycle. These are:

1. The steam pressure and temperature used in the cycle; the higher the better within the cost

constraints imposed by the physical, chemical and metallurgical boundaries within which

the plant has to operate. Available skills levels also play a role in setting cycle parameters.

2. The condenser pressure.

Figure 12: Temperature gradients through contra and parallel flow air heaters.

Contra flow Airheater Parallel flow AirheaterGAS GAS

363°C 363°C

AIR

247°C 25°C

288°C

AIR

25°C 247°C

273°C 273°C

cold corner min

metal temp at

intermediate

tube plate

cold corner

min metal

temp at

lower tube

plate136°C

152°C


431

3. The amount of steam that can be bled off from the turbine to do useful work prior to the

condenser. In an export co-generation facility hosting a cane sugar factory, steam is

mainly bled to supply the factory’s process needs and for feed water and combustion air

heating.

Export co-generation cycles typically operate at turbine inlet stop valve conditions of about

43, 60 or 80 bar (g). Allowing a 2 bar pipeline pressure drop between the boiler and turbine

and a pressure drop of about 7% of the boiler stop valve pressure across the superheater, the

saturation temperatures in the boiler are 241°C for the 30 bar cycle and 262, 282 and 302°C

for the 43, 60 and 80 bar cycles respectively.

Magasiner (1996) deals with the effect that increasing cycle pressure has on boiler heating

surface configuration. The author shows that a number of design changes are required in order

to optimise boiler performance for the higher pressures required for co-generation. First, more

furnace heating surface and hence a taller furnace is required to compensate for the higher

saturation temperature and to make space for the superheater radiant heating surface needed

for the higher steam temperature. Then, because the saturation temperature is higher, the gas

temperature leaving the convection pass is higher. This all results in the back end design

being dominated by an economiser rather than an air heater.

The reason for the switch in dominance is as follows. The maximum air temperature leaving

the air heater is dictated by the maximum allowable air temperature that can be tolerated by

the combustion equipment and, sometimes even more importantly, by the clinkering

characteristics of the fuel. Increasing the gas temperature to the air heater makes the air heater

work harder. So much so that at a pressure of 62 bar a single pass air heater is able to do about

the same amount of work as a two pass unit operating in conjunction with a 30 bar boiler. At

82 bar it is debateable whether a commercial case for a gas/air air heater can be made at all.

From the power cycle efficiency point of view, equipping the boiler with an economiser and a

steam heated air heater using steam bled from the turbine is often the optimum solution.

Table 2 schedules the anticipated performance of the backend of a typical 200 t/h, 62 bar

bagasse fired co-generation boiler. The unit has been sized to operate with feed at 130°C to

ensure that the economiser metal temperature is above the H2SO4 ADP when burning bagasse

having a high (0.1%) sulphur content. This temperature can be obtained by operating the de-

aerator at 2.7 bar, or by interposing a feed water heater between a de-aerator operating at

105°C and the economiser. In both cases steam bled from the turbine can be used as a

hearting medium for the de-aerators and the feed water heater.

Six different plant arrangements are scheduled. Three investigate plant performance with the

economiser placed ahead of the air heater and three with the air heater placed ahead of the

economiser.

Placing the economiser ahead of the air heater maximises the temperature differences between

sources and sinks and hence the potentials driving heat transfer between flue gas and heated

fluid: i.e. feed water at 130°C and air at 25°C. However, with this arrangement the air heater

is far more susceptible to corrosion.


432

In all cases the heat recovery plant has been sized to bring the final gas temperature down to

177°C when steaming at MCR. At lower loads the final gas temperature depends on plant

configuration and is, therefore, not necessarily always the same for all arrangements. The

performance figures are based on burning bagasse having a moisture content of 52 % and an

ash content of 2%. The calculations include the variation in excess air level with primary air

temperature as shown in Appendix 3. These corrections are relatively minor. The primary air

temperature is limited to a maximum of 250°C to allow for operation with a continuous ash

discharge stoker using ‘HS Meehanite’ or equal cast iron grate bars.

The six arrangements are:

A. Economiser followed by a two pass parallel flow air heater. With this arrangement the

economiser is 64% as big as the one included in arrangement F (base case) and the air

heater is over 50% bigger. This is because it operates in a cooler environment where the

temperature difference between gas and air is lower.

B. Economiser followed by a two pass contra flow air heater. The economiser in this instance

is identical to the one included in arrangement A but, because the air heater is a contra

flow rather than a parallel flow unit, it is only 96% as big as the one included in

arrangement F.

A B C D E F

Load

Economiser

with

Parallel Flow

A/H

Economiser

with

Contra Flow

A/H

Economiser

with

Contra Flow

A/H (same

heating

surface

geometry as

for A)

Load

Parallel Flow

A/H

with

Economiser

Contra Flow

A/H

with

Economiser

Single Pass

A/H

with

Economiser

100% Economiser water inlet 130 130 130 °C 100% Air through air heater 65 65 65 °C

Economiser water outlet 220 220 220 °C Air heater gas inlet 392 392 392 °C

Economiser gas inlet 393 393 392 °C Air heater gas outlet 303 303 303 °C

Economiser gas outlet 236 236 248 °C Air temp in 25 25 25 °C

Minimum metal temp 131 131 131 °C Air temp out 247 247 247 °C

∆∆∆∆Tg/∆∆∆∆Tw 1.74 1.74 1.60 Minimum metal temp 142 127 160 °C

Saturation temp 282 282 282 °C ∆∆∆∆Tg/∆∆∆∆Ta 0.40 0.40 0.40

Relative heating surface 0.64 0.64 0.54 Relative heating surface 1.03 0.79 1.00

Air through air heater 65 65 65 % Economiser water inlet 130 130 130 °C

Air heater gas inlet 234 234 246 °C Economiser water outlet 200 200 200 °C

Air heater gas outlet 177 177 177 °C Economiser gas inlet 303 302 302 °C

Air temp in 25 25 25 °C Economiser gas outlet 177 177 177 °C

Air temp out 160 160 190 °C Minimum metal temp 131 131 131 °C

Minimum metal temp 102 92 101 °C ∆∆∆∆Tg/∆∆∆∆Tw 1.80 1.78 1.79

∆∆∆∆Tg/∆∆∆∆Ta 0.42 0.42 0.42 Saturation temp 282 282 282 °C

Relative heating surface 1.51 0.96 1.51 Relative heating surface 1.00 1.00 1.00 %

Boiler efficiency 67.5 67.5 66.6 % Boiler efficiency 67.6 67.6 67.6 %

Relative power consumption 1.6 1.8 1.4 Relative power consumption 2.1 2.7 1.0

60% Economiser water inlet 130 130 130 °C 60% Air through air heater 68 68 68 %

Economiser water outlet 213 213 215 °C Air heater gas inlet 346 346 346 °C

Economiser gas inlet 346 346 346 °C Air heater gas outlet 261 259 259 °C

Economiser gas outlet 206 206 206 °C Air temp in 25 25 25 °C

Minimum metal temp 131 131 131 °C Air temp out 219 223 223 °C

∆∆∆∆Tg/∆∆∆∆Tw 1.68 1.68 1.66 Minimum metal temp 114 102 130 °C

Saturation temp 282 282 282 °C ∆∆∆∆Tg/∆∆∆∆Ta 0.44 0.44 0.44

Air through air heater 68 68 68 % Economiser water inlet 130 130 130 °C

Air heater gas inlet 205 205 205 °C Economiser water outlet 189 188 188 °C

Air heater gas outlet 154 150 160 °C Economiser gas inlet 261 259 259 °C

Air temp in 25 25 25 °C Economiser gas outlet 160 160 160 °C

Air temp out 143 143 123 °C Minimum metal temp 131 131 131 °C

Minimum metal temp 84 75 87 °C ∆∆∆∆Tg/∆∆∆∆Tw 1.71 1.70 1.70

∆∆∆∆Tg/∆∆∆∆Ta 0.43 0.47 0.46 Saturation temp 282 282 282 °C

Boiler efficiency 68.8 69.1 69.1 % Boiler efficiency 68.6 68.6 68.6 %

Boiler with Economiser followed by an Air Heater

TABLE 2 - Back End Arrangements - Comparison Based on Constant MCR Final Gas Temperature

Boiler with Air Heater followed by an Economiser


433

C. Economiser followed by a two pass contra flow air heater having the same physical

dimensions as the air heater included in arrangement A. The economiser in this

arrangement is less expensive, being only 54% as big as the one included in arrangement

F.

D. Two pass parallel flow air heater followed by an economiser. In this case the air heater is

just a little larger than the one included in arrangement F. The economiser is the same size

but over twice as much fan power is required by the heat recovery plant than is required

by arrangement F.

E. Two pass contra flow air heater followed by an economiser. This arrangement includes

the same economiser as is used in arrangement D. The air heater is smaller because of the

contra flow rather than parallel flow configuration. Nearly 2.75 times more fan power is

required by the heat recovery plant than is required by arrangement F.

F. Single pass air heater followed by an economiser. This is the base case. Here again the

economiser is the same size as that used in arrangement D, although the air heater is a

little smaller.

Arrangements D, E and F are able to provide air at higher temperatures than arrangements A,

B and C. This means that boilers equipped with D, E or F will have lower unburnt losses and

combustion will be more stable. This is reflected in the efficiencies they are able to achieve.

The Verhoff and Banchero (1974) equation calculates the H2SO4 ADP of 52% moisture

bagasse having a DAF sulphur content of 0.1% at about 129°C (for a DAF content of 0.01% it

is about 110°C). This is much higher than the calculated minimum metal temperatures that

arrangements A, B or C can achieve. For the ADP to be higher than 102°C, i.e. higher than

the minimum metal temperatures for arrangements A and C, the maximum sulphur content

may not exceed 0.002%. Placing the air heater after the economiser when burning most

bagasse types is therefore not practical.

Because backend arrangements D and E need so much more fan power, they are not as viable

commercially as arrangement F.

At 60% load the minimum metal temperature of arrangement E (102°C) is too low for all but

those fuels having a very low DAF sulphur level. With arrangement F having about the same

heating surface as arrangement D but being able to operate with a minimum metal

temperature of at least 130°C over an operating range of 60 to 100% MCR, and requiring only

about half as much power, F is clearly the best possible arrangement.

Notes on improving boiler and cycle efficiency

The efficiency of a boiler with air heater up front can be improved by adding extra

economiser heating surface. The improvement for a 52% moisture, 2% ash fuel is illustrated

in Figure 13. It is up to the designer together with the purchaser to do the cost/benefit studies

to determine the extent of heat recovery surface to install. When doing this exercise the

change in fan power consumption as a result of the change in heating surface must be taken in

to account.


434

The efficiency can also be improved by reducing the feed water temperature provided the

metal temperature is not allowed to drop below the H2SO4 ADP. Figure 14 typically

illustrates how final gas temperature drops as feed water temperature is reduced and how this

impacts on efficiency for a boiler burning bagasse having a moisture content of 52% and an

ash content of 2%.

As an alternative to fitting an economiser,

making the air heater work harder by

passing 100% of the combustion air

through it may in a conventional mill

sometimes be the better commercial

option. This arrangement reduces the final

gas temperature by about 20°C rather than

the ~125°C that can be obtained from an

economiser. The gain in efficiency with

this arrangement is, unfortunately, often

largely offset by the extra power required

to drive the overfire air fan (Magasiner

1974).

In the above examples, where the

economiser is placed after the air heater,

the water temperature leaving the

economiser at 200°C is well below boiling

point (282°C). To avoid steaming at MCR

the water leaving temperature should be

about 30°C lower than the boiling point.

This leaves room for enhancing the efficiency

of the power cycle by bleeding more steam

from the turbine into an economiser inter-

bank feed water heater. By placing this heater

between banks rather than at the inlet to the

economiser, the minimum sink temperature;

i.e. the feed water temperature can be kept at

the required level above the H2SO4 ADP thus

maintaining the temperature potential between

flue gas and water and hence the possibility of

achieving optimum boiler efficiency.

General notes on heat recovery plant

performance

An interesting feature of two pass parallel

flow air heaters is that most of the work is

done in the first pass and only a small

fraction is done in the second. From Figure

12, work done in first pass ~ (363 – 288)/(363

– 273) x 100 = 83%.

Figure 14: Affect on final gas temperature and efficiency as a function of feed water temperature

Feed Water Temp vs

Final Gas Temp & Efficiency

140

150

160

170

180

190

105 110 115 120 125 130

Feed Water Temperature oC

Final Gas Temperature oC

99

100

101

102

103

104

Relative Efficiency

Final Gas Temp (MCR)

Final Gas Temp (60% MCR)

Relative Efficiency (MCR)

Relative Eff iciency (60% MCR)

Figure 13. Effect of increasing economiser heating surface on the performance of a boiler firing 52%

moisture, 2% ash bagasse.

Final Gas Temp vs

Economiser Relative Heating Surface &

Efficiency

120

130

140

150

160

170

180

190

200

210

220

0.5 1 1.5 2 2.5 3

Economiser Relative Heating Surface

Final Gas Temp oC

95

96

97

98

99

100

101

102

103

104

105

Relative Efficiency

Feed Water Temp

Final Gas Temp

Relative Eff iciency


435

The air heater performance figures shown in Figure 12 and Table 2 assume that at MCR 65%

of the total combustion air required is delivered as primary air to the grate with the balance

being delivered as cold overfire air. At 60% load, more excess air is used. The O2 level can be

as much as 1% higher. Table 2 figures take cognisance of this.

How air heater metal temperature varies with load

From Table 2 it is clear that gas temperature falls as load falls which in turn means that metal

temperature, which is a function of gas temperature, falls as well. In fact, air heater metal

temperature falls more rapidly than would be anticipated from a simple analysis of the fall in

gas temperature.

The reason for this is as follows. In cane sugar industry boilers gas normally flows through

the tubes and air flows over the tubes. For gas flowing through the tubes the heat transfer

coefficient kg is ~Vg0.8 and for air flowing over the tubes the heat transfer coefficient is ~Va

0.6

where Vg is the gas velocity through the tubes and Va the air velocity over the tubes. As load

falls, therefore, the gas side coefficient falls off more rapidly than the air side coefficient,

which in turn means that with falling load metal temperature is lower than anticipated and

hence the corrosion problem is aggravated. (If velocities drop by half, Vg0.8 = 0.574 times and

Va0.6 = 0.660 times the previous values.)

Backend plant arrangements

After extracting as much heat as is economically feasible from the flue gas it is exhausted

through a dust collector, an induced draft fan and a chimney. Each of these components as

well as the ducting carrying the flue gas is vulnerable to corrosion. Where a wet scrubber is

used to collect dust the exhaust from the scrubber will be saturated with water vapour. The

water used for scrubbing is usually dosed with an alkali in sufficient quantity to ensure that

the gases and fluids leaving the scrubber are not corrosive.

With dry collecting systems the flue gas temperature from the heat recovery plant is usually

high enough to ensure that the ducting, collector, ID fan and chimney operate above the dew

point without lagging. In windy and/or colder areas such as Eston, Dalton and Noodsberg

where ambient air temperatures are sometimes fairly low, measures should be taken to protect

these components.

Conclusions

Corrosion is experienced in a boiler whilst it is in operation wherever metal temperatures drop

below the ADP of the flue gas. The H2SO4 ADP is largely dependent on the sulphur content

of the fuel which oxidises to SO2 during the combustion process and on the proportion of SO2

that converts to SO3. SO3 in turn converts to H2SO4 as the gas cools down from 400°C.

Chlorine in the fuel can convert to HCl during the combustion process. While the dew point

of HCl is lower than that of H2SO4, recent studies show that chlorine can under certain

circumstance be aggressive at higher than HCl’s normal ADP if zinc and calcium are also

present.

Both the H2SO4 and HCl ADPs are dependent on the concentrations by volume of water


436

vapour, SO2 and HCl in the flue gas. Graphs and formulae provided in this paper enable the

boiler designer and boiler operator to determine the dew points of both these acids.

Air heater and economiser corrosion occurs when the temperature of the metal from which

these components are made drops below the ADP. The gas temperature can be well above the

dew point for this phenomenon to occur. The phenomenon is analogous to one’s spectacles

misting over when getting out of a cold air conditioned car into a hot, humid environment.

With export co-generation becoming more attractive, more boilers are being installed to

operate at higher pressures. The higher saturation temperatures associated with these

pressures reduces the effectiveness of the boiler radiant and convective passes, thus requiring

the heat recovery or backend of the unit to work harder. The paper shows that as pressure

rises a single pass air heater placed upstream of the economiser provides the best corrosion

resistant solution. It also shows that with gas through tube air heaters, as load falls dew point

falls faster than can be expected because of the way in which heat transfer coefficients vary

with load. At higher pressures a steam heated air heater is often the best solution. (Warning:

Take precautions at the design stage to ensure that airborne dust does not clog the air side of

these units.)

While careful plant design can minimise the risk of corrosion occurring, operators can also

prevent corrosion by ensuring that in the case of economisers feed water heaters are used

correctly to preheat the feed water and in the case of air heaters, air is bypassed around the air

heater to maintain metal temperatures above the ADP. Temperature probes should be inserted

into economiser and air heater tubes where the lowest metal temperatures are expected in

order to monitor the temperatures of these components.

By being aware of the ADPs of the fuels being burned the operator can adjust the feed water

temperature or air heater bypass, if applicable, to maximise plant efficiency. For economisers

it is best to use a feed water temperature at least 5°C higher than the calculated ADP and in

the case of an air heater, a metal temperature at least 10°C higher. Air heaters require higher

margins because their metal temperatures fluctuate over much larger ranges. Having

established a theoretical dew point it is very important to regularly inspect the areas where

corrosion can be expected to occur in order to verify that the predictions are valid. Having

established an inspection regime, the operator can ‘fine tune’ the feed water or, if applicable,

the air heater metal temperature to achieve best results. Calculated ADPs should be revisited

whenever fuel qualities change.

In geographical areas where windy and/or colder ambient air temperatures are experienced

stack metal temperatures should also be monitored.

To complete the corrosion picture, Appendix 4 includes a note on high temperature corrosion.

Acknowledgement

The author thanks Dr John de Kock for reviewing this paper and for his advice regarding the

physical chemistry.


437

REFERENCES

Jensen JP, Fenger LD and Henriksen N (2001). Cold-end corrosion in biomass and waste incineration

plants. PowerPlant Chemistry 2001: 3(8).

Lindau L and Goldschimdt B (2008). Low temperature corrosion in bark fueled, small boilers.

Varmeforsk Services AB M9-835.

Magasiner N (1974). Boiler plant as an integral part of a cane sugar factory. Proc Int Soc Sug Cane

Technol 15: 1642-1679

Magasiner N (1996). Bagasse-fired boiler design with reference to co-generation. Int Sug J Vol

XCVIII, No. 1167: 100-109.

Magasiner N, van Alphen C, Inkson MB and Misplon BJ (2001). Characterising fuels for biomass-

coal fired co-generation. Proc S Afr Sug Technol Ass 75: 282-291.

Okkes AG and Badger BV (1987). Get acid dew point of flue gases. Hydrocarbon Proc 66(7): 53.

Rein P (2007). Cane Sugar Engineering. Verlag Dr Albert Bartens KG, Berlin, ISBN 978-3-87040-

110-8; Ch 27, Figures 27.11 and 27.12.

Srivastava RK, Miller CA, Erickson C.and Jambhekar R (2002). Emissions of sulphur trioxide from

caol-fired power plants. POWER-Gen Int 2002: 5-9.

Verhoff FH. and Banchero JT (1974). Predicting dew points of flue gases. Chem Eng Progr 70(8): 71.

Yen-Hsiung Kiang (1981). Predicting dew points of acid gasses. Chem Eng Feb 9.


438

Appendix 1 – Formulae

Sulphuric Acid Dew Point (Verhoff and Banchero, 1974)

1000/TdpS = 2.276-0.02943*ln(PH2O)-0.0858*ln(PSO3)+0.0062*ln(PH2O)*ln(PSO3) (1)

where:

TdpS is the H2SO4 dew point temperature in °K

P is the partial pressure in mm Hg.

Sulphuric Acid Dew Point (Okkes and Badger, 1987)

Tdp = 203.25+27.6*log10(PH2O)+10.83*log10(PSO3)+1.06*(log(PSO3)+8)

2.19 (2)

where:

TdpS is the H2SO4 dew point temperature in °C

P is the partial pressure in atm.

Hydrochloric Acid Dew Point (Yen-Hsiung Kiang, 1981)

1000/TdpH = 3.7368-0.1519*ln(PH2O)-0.0326*ln(PHCl)+0.00269ln*(PH2O)*ln(PHCl) (3)

where:

TdpH is the HCl dew point temperature in °K

P is the partial pressure in mm Hg.

Continued…..


439

Appendix 1 – Formulae (continued)

The following form

ulae can be used in place of the graphs to provide input data for Appendix 2:

where:

A

= Ash content %

H

2O

= Free + Inherent moisture content %

O

2

= W

et gas O

2 in flue gas %

SDAF = Sulphur content % (DAF for bagasse) %

Sf

= Sulphur content % (‘as fired’ for coal) %

H

2

= ‘as fired’ H

2 content of coal %

NOTE:

The form

ulae and graphs yield results accurate to about ± 3%. This m

argin of error makes little difference to the calculated ADP.

Bagasse

Vol H

20 %

= [(9.5722*(A

/100)2+0.1546*A/100+0.5589)*H

2O+(-460.99444*(A

/100)2+18.69794*A/100+.23339)]*(-0.0519*O

2+1.1557)

[cell B10]

Vol SO

2 % = (-0.00001774*H

2O+0.00325203)*SDAF/0.025*(-0.0575*O

2+1.1725) [cell B13]

Coal

Vol H

20 %

= (-0.0085*O

2+0.1995)*H

2O+(-0.062*O

2+1.316)*H

2+(-0.0455*O

2+3.2215) [cell C10]

Vol SO

2 %

=

At 0,3 %

S = (-0.000014*O

2+0.000303)*H

2O+(-0.001374*O

2+0.02907)

At 2,0 %

S = (-0.000097*O

2+0.002076)*H

2O+(-.00922*O

2+0.195547)

At Sf % S = (2,0%S-0,3%S)*(S

f-0,3)/(2,0-0,3)+0,3%S [cell C13]


440

Appendix 2 – Quick method of calculating acid dew point when dual firing.

A B C D E

1

2 ENTER Proportion by mass of bagasse burned 0.9 =(1-B2)

3 ENTER % O2 in wet exhaust gas 5.0 %

4 Bagasse Coal Comments

5 ENTER fuel H2O content (inherent+free) (M) % 52.0 5.0 % From fuel analysis

6 ENTER fuel H2 content (H2) % 3.5 % From fuel analysis

7 ENTER fuel S content (S) % 0.05 0.85 % For Bagasse "DAF"; For Coal "as fired"

8 ENTER fuel ash content(A) % 2.0 12.8 % From fuel analysis

9 ENTER fuel brix content (s) % 1.6 From fuel analysis

10 ENTER volume of H2O in flue gases 26.7 7.3 % From Figs 4 and 8

11 "As fired" volume of H2O in flue gases =B10*B2 =C10*C2 %

12 Volume of H2O in mixture of flue gases =B11+C11 %

13 ENTER volume of SO2 in flue gases 0.0041 0.0683 % From Figs 5 and 9

14 "As fired" volume of SO2 in flue gases =B13*B2 =C13*C2 %

15 ENTER % mass S02 converted to SO3 2.00 0.50 %Assumes 2,0 % SO2 converted to SO3 on bagasse

Assumes 0,5 % SO2 converted to SO3 on coal

16 "As fired" volume of SO2 converted to SO3 =B14*B15*64/80/100 =C14*C15*64/80/100 %SO2/SO3 conversion is on a mass basis hence the

need to multiply by ratio of mol masses; i.e. 64/80

17 Volume of SO2 converted to SO3 in flue gases B16+C16 %

18 ENTER GCV of coal bagasse GCV equation 26,620 kJ/kgFor bagasse : =196.05·(100 -M - A) - 31.14·s

For coal : From fuel analysis

19 ENTER GCV efficiency 63.4 78.6 %From Rein (2007) Figs 27.4 and 27.5 respectively.

Say final gas temeperature = 240oC and O2 = 3%

20 Effective GCV =B18*B19/100 =C18*C19/100 kJ/kg

21 "as fired" GCV of mixture =(B20*B2)+(C20*C2) kJ/kg

22 Load on each fuel =B20/C21*B2*100 =(100-B22) %Use "Goal Seek" to obtain desired load on coal.

Vary cell B2

23

24

25 Volume of H2O in mixture of flue gases =C12 % vol in gas

26 Wet Gas O2 =B3 % vol in gas

27 Volume of SO2 converted to SO3 in flue gases =C17 % vol in gas

28 ENTER site Altitude 80 masl

29 Bara pressure bara pres equation bar

30 ENTER gas pressure in duct -2,500 Pa

31 =B30/100000 bar

32 Bara pressure in duct =B29+B31 bar

33 PH2O =B25*B32*760/100 mm Hg

34 =LN(B33) ln(PH20)

35 PSO3 =B27*B32*760/100 mm Hg

36 =LN(B35) ln(PSO3)

37 1000/Tdp V + B equation

38 Tdp =1000/B38oK

39 ACID DEW POINT TEMP Tdp =B39-273.15oC

ENTER Proportion by mass of bagasse burned 0.90 0.10

ENTER % O2 in wet exhaust gas 5.0 %

Bagasse Coal Comments

ENTER fuel H2O content (inherent+free) (M) % 52.0 5.0 % From fuel analysis

ENTER fuel H2 content (H2) % 3.5 % From fuel analysis

ENTER fuel S content (S) % 0.05 0.05 % For Bagasse "DAF"; For Coal "as fired"

ENTER fuel ash content(A) % 2.0 14.6 % From fuel analysis

ENTER fuel brix content (s) % 1.6 From fuel analysis

ENTER volume of H2O in flue gases 26.7 7.3 % From Figs 4 and 8

"As fired" volume of H2O in flue gases 24.1 0.7 %

Volume of H2O in mixture of flue gases 24.8 %

ENTER volume of SO2 in flue gases 0.0041 0.0037 % From Figs 5 and 9

"As fired" volume of SO2 in flue gases 0.0037 0.0004 %

ENTER % mass S02 converted to SO3 2.00 0.50 %Assumes 2,0 % SO2 converted to SO3 on bagasse

Assumes 0,5 % SO2 converted to SO3 on coal

"As fired" volume of SO2 converted to SO3 0.0000594 0.0000015 %SO2/SO3 conversion is on a mass basis hence the

need to multiply by ratio of mol masses; i.e. 64/80

Volume of SO2 converted to SO3 in flue gases 0.000061 %

ENTER GCV of coal 8,989 26,620 kJ/kgFor bagasse : =196.05·(100 -M - A) - 31.14·s

For coal : From fuel analysis

ENTER GCV efficiency 63.4 78.6 %From Rein (2007) Figs 27.4 and 27.5 respectively.

Say final gas temeperature = 240oC and O2 = 3%

Effective GCV 5,699 20,923 kJ/kg

"as fired" GCV of mixture 7,222 kJ/kg

Load on each fuel 71.0 29.0 %Use "Goal Seek" to obtain desired load on coal.

Vary cell B2

Volume of H2O in mixture of flue gases 24.8 % vol in gas

Wet Gas O2 5.0 % vol in gas

Volume of SO2 converted to SO3 in flue gases 0.0000609 % vol in gas

ENTER site Altitude 80 masl

Bara pressure 1.0037 bar

ENTER gas pressure in duct -2,500 Pa

-0.0250 bar

Bara pressure in duct 0.9787 bar

PH2O 184.4855 mm Hg

5.2176 ln(PH20)

PSO3 0.0004527 mm Hg

-7.7002 ln(PSO3)

1000/Tdp 2.5340

Tdp 394.6oK

ACID DEW POINT TEMP Tdp 121.5 oC

=2.276-0.02943*B34-0.0858*B36+0.0062*B34*B36

=(5.183865*10-7*masl2-0.011985*masl+101.325)/100

Verhoff and Banchero Method

Sulphuric Acid Dew Point (PROGRAM)

Say 80 masl

Proportion by mass of coal burned

Comments

Measured in exhaust duct

Sulphuric Acid Dew Point (WORKED EXAMPLE)

Verhoff and Banchero Method Comments

= C6

Proportion by mass of coal burned

=(5.183865*10-7*masl2-0.011985*masl+101.325)/100

Measured in exhaust duct

= B3

= C10


441

Appendix 3 – Relationship Between Excess Air (%) and Wet Gas O2 (%)

Rein (2007), ch 27 provides an indication of the way in which excess air may vary with fuel

effective moisture and undergrate air temperature. The chart below shows how wet gas O2%

varies with excess air when following the relationship published by Rein.

Note on ‘Effective Moisture’: As ash content increases the ratio of moisture to combustible

material increases. This has a negative impact on the combustibility of the fuel. The concept

of effective moisture is introduced to correct for this phenomenon.

Effective moisture is defined as:

where:

We = Effective moisture %

W = Measured Moisture %

A = Ash content %

Excess Air and O2 vs Bagasse Effective Moisture

0

5

10

15

20

25

30

35

40

45

46 47 48 49 50 51 52 53 54 55 56

Bagasse Effective Moisture (%)

Excess Air (%)

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

6.0

6.5

Wet Gas O2 (%)

0oC

100oC

200oC

300oC

Excess Air

O2

(100 - 2)

(100 - A)We = W·


442

Appendix 4 – Notes on High Temperature Superheater and Furnace Corrosion

Extracts from Fuel Handbook; Edited by Birgitta Stromberg; Published by Värmeforsk

Service AB (March 2006), ISSN 0282-3772: pp 43-46.

“5.1 Superheater corrosion

Serious corrosion attack on Superheater surfaces has been reported from a number of steam boilers

fired with biofuel. The corrosion is usually taken to be related to the composition of the fuel and the

boiler steam conditions. However, no consistent pattern has emerged, possibly with the exception of

the fact that all the boilers generate steam at 500°C.

Superheater corrosion often occurs due to high material temperatures in combination with the alkaline

compound phases with low melting points and a reducing atmosphere, which may occur if the fuel is

not completely burned when it reaches the superheater. Four main reasons for corrosion attack have

been identified:

• Initial melting point of the ash

• Efficiency of final combustion

• Surface temperature of superheated tubes

• Unbalance on the steam and flue gas sides.

The melting point of the ash depends on the ash composition, where principally enrichment of

potassium and chloride is of significance. The temperature of the superheater tube is determined by the

steam temperature and also by the flue gas temperature and by the boiler design. If the boiler is fired

by waste fuels, such as waste wood, other problematic compounds often also occur and these contain,

for example, zinc, lead and tin.

One form of superheater corrosion that has long been known is described as coal ash corrosion. The

name originates from coal firing, but the same type of corrosion may also occur when the boiler is

fired with other fuels. A prerequisite for coal ash corrosion is that the fuel has a substantial sulphur

content (also reckoned on the ash). A deposit of low melting point sulphates of Na and K may form on

the superheater surfaces. This sulphate melt attacks the passivating oxide film on the metal

(principally Fe) and exposes the unprotected metal surfaces to corrosion attack. This sulphate

corrosion type occurs within the temperature range 566-732°C.

Many new and older fossil-fired plants built for or converted to biofuel-based power (CHP) generation

have suffered superheater corrosion problems soon after commissioning. A common denominator is

that the plants have relatively advanced steam conditions, generally with steam temperatures of 480-

500°C, and that they use 100% biofuels.

The corrosion situation deteriorates if Cl is available in the fuel system. Superheater deposits then

begin to form at lower temperatures, and the formation of deposits often begins with condensation of

low-volatility chlorides (of K and Na) on the superheater surface. The corrosion mechanism in this Cl-

induced superheater corrosion is also related to sulphates and the interaction of several reactions:

• Formation of chloride melts

• Sulphating of the chloride melts under the influence of SOx

• Local formation of HCl and of Cl2 close to the metal

• Transfer of the metal in metal chlorides and sulphates

• Oxidation of these primary products to metal oxides (‘rust’), while the chlorine partially reverts

back to the corrosion mechanism.

This mechanism in which Cl participates may begin at temperatures that are 50°C lower than the pure

sulphate mechanism in coal ash corrosion.

The situation is even worse when the melting point and thus the threshold for the formation of salt

melts on the superheater surfaces are lowered further. This can take place when transition metals that


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may form volatile chlorides and sulphates with low melting points are included in the fuel system in

significant quantities. Examples of such melting point lowering elements are Cu, Pb, Zn. These

commonly occur in industrial waste and other industrial recovered fuels, and also in demolition wood,

for instance.”

“5.3 Furnace corrosion

Combustion engineering measures for NOx reduction, such as combustion in stages, can result in

locally reducing conditions and increases the risk of furnace corrosion that comprises various

conceivable mechanisms jointly designated as CO corrosion. The name CO corrosion originates from

the fact that it occurs at high CO contents in the gas which is a direct consequence of oxygen

deficiency. The most important mechanism in CO corrosion is a reaction between the carbon from

CO, for instance, with the structural metals. CO (or C in some other form) can be adsorbed on the

metal surface where it begins to react, when C is formed. This C diffuses into the metals and forms so-

called inclusion carbides (carbides: compounds of carbon and some metal).Inclusion carbides are also

known as interstitial carbides. Examples of inclusion carbides that may form are:

Iron: Fe3C (cementite, iron carbide)

Fe2C

Chromium: Cr23C6

Cr7C3

Cr3C2

Nickel: Ni3C

The first of these carbides is a common constituent of carbon steels. But crystallization and grain

formation problems occur when these carbides are formed in excessive quantities. This is what

happens in CO corrosion, whereby the metal alloy is fragmented by the gradual formation of inclusion

carbides that form their own grains in a metal structure and gradually burst the as yet unaffected metal

matrix. The mechanism is also described in 1.

As shown by the table above, all important alloying metals in high-grade structural steels can be

attacked by the formation of inclusion carbides.

In the presence of sulphur, hydrogen sulphide corrosion is the most important corrosion mechanism

under reducing conditions. The formation of metal sulphides and oxides is determined by equilibrium

relationships. The formation of sulphides is promoted when the partial pressure of sulphur is high and

the oxygen partial pressure is low. High chlorine contents are a secondary contributory factor. In this

case too, measures for NOx reduction can also affect corrosion. As in the case of superheater

corrosion, molten ash constituents may dissolve the protective oxide film and contribute to corrosion.

Since the material temperature on the furnace walls is lower than in the superheater, parts of the ash

must still be molten at that particular temperature. Under reducing conditions, the slag formation

properties of the ash are changed and the melt temperature may be lowered. Suppliers consider that

corrosion problems can be avoided by designing the burners and air supply in such a manner that

reducing conditions at the walls will be avoided. Care must be given to the distribution of the fuel

between different burners and to the fuel particle size distribution. Distorted distribution at the fuel

entry may lead to locally reducing conditions.

In fluidized beds, the corrosion rate varies locally in the bed. This is related to the varying partial

pressure of oxygen. Even if the bed is run with excess air overall, local zones with sub-stoichiometric

conditions occur. The risk of corrosion increases if a sulphur absorber is added. At low local oxygen

concentrations, the equilibrium between calcium sulphate and calcium oxide may lead to the release of

corrosive sulphur, which may lead to sulphuration of the metal components in the bed. If waste fuel

such as waste wood is fired, difficult compounds containing zinc, lead and tin may also occur.

1Grabke H.J. Corrosion by carbonaceous gases. Carburization and metal dusting and methods of prevention.

Materials at high temperatures 17 (4). 483-487 (2000).”


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Backend corrosion in bagasse-coal fired boilers with … CORROSION IN BAGASSE – COAL FIRED BOILERS WITH PARTICULAR REFERENCE TO CO-GENERATION MAGASINER N Magasiner Technology, 6