boilers & furnaces - guide book
TRANSCRIPT
BOILERS &FURNACES
G u i d e B o o k 2
3E STRATEGY
BOILERS &FURNACES
G u i d e B o o k 2
3E STRATEGY
ST
RA
TE
GY
EFFICIENCYENERGY
EARNINGS
EUROPEAN COMMISSION
Ne the r l an d s M in i s t e r y o f E c onom i c A f f a i r s
TSI
Technical Services International
M
YI N GRE ER A NL ES DA N
How
to sav
e ene
rgy a
nd mo
ney
• • • • • • • • • • • • • •HOW TO SAVE
ENERGY AND MONEY
IN BOILERS AND FURNACE SYSTEMS
This booklet is part of the 3E strategy series. It provides advice onpractical ways of improving energy efficiency in boilers and furnacesystems.
Prepared for the European Commission DG TREN by:
The Energy Research InstituteDepartment of Mechanical EngineeringUniversity of Cape TownRondebosch 7700Cape TownSouth Africawww.eri.uct.ac.za
This project is funded by the European Commission and co-funded bythe Dutch Ministry of Economics, the South African Department ofMinerals and Energy and Technology Services International , with theChief contractor being ETSU.
Neither the European Commission, nor any person acting on behalf ofthe commission, nor NOVEM, ETSU, ERI, nor any of the informationsources is responsible for the use of the information contained in thispublication
The views and judgements given in this publication do not necessarilyrepresent the views of the European Commission
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HOW TO SAVEENERGY AND MONEY
IN BOILERS AND FURNACESYSTEMS
• • • •
• • • • • • • • • • • • • •HOW TO SAVE
ENERGY AND MONEY
IN BOILERS AND FURNACE SYSTEMS
Other titles in the 3E strategy series:
HOW TO SAVE ENERGY AND MONEY:THE 3E STRATEGYHOW TO SAVE ENERGY AND MONEY IN ELECTRICITY USEHOW TO SAVE ENERGY AND MONEY IN STEAM SYSTEAMSHOW TO SAVE ENERGY AND MONEY IN COMPRESSED AIR SYSTEMSHOW TO SAVE ENERGY AND MONEY IN REFRIGERATIONHOW TO SAVE ENERGY AND MONEY IN INSULATION
Copies of these guides may be obtained from:
The Energy Research InstituteDepartment of Mechanical EngineeringUniversity of Cape TownRondebosch 7700Cape TownSouth AfricaTel No: (+27 21) 650 3892Fax No: (+27 21) 686 4838Email: [email protected]: http://www.3e.uct.ac.za
ACKNOWLEDGEMENTS
The Energy Research Institute would like to acknowledge the following for their contribution in the production ofthis guide:
• Energy Technology Support Unit (ETSU), UK, for permission to use information from the “EnergyEfficiency Best Practice” series of handbooks.
• Wilma Walden of Studio.com for graphic design work ([email protected]).• Doug Geddes of South African Breweries for the cover colour photography.• Canadian gov. See other guides.
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G u i d e B o o k E s s e n t i a l s :QUICK ‘CHECK-LIST’ FOR SAVING ENERGY
and MONEY IN BOILERS AND FURNACE
SYSTEMS
This list is a selected summary of energy and cost savings opportunities outline in the text. Manymore are detailed in the body of the booklet.These are intended to be a quick ‘checklist’.
BOILERS (CHAPTER 9)
• Maintain efficient combustion.• Maintain good water treatment.• Repair water and steam leaks.• Recover heat from flue gas and boiler blowdown whenever possible (see Steam
guidebook).• Ensure good operational control and consider sequence control for multi-plant
installations).• Attempt to match boilers to heat demand. Valve off idle boilers to reduce radiation
losses.• Use flue dampers where appropriate to minimize flue losses when the plant is not firing.• Ensure that boilers and heat distribution systems are adequately insulated.• Blowdown steam boilers only when necessary (see Steam guidebook).• Ensure as much condensate as practicable is recovered from steam systems.• Insulate oil tanks and keep steam or electric heating to the minimum required.
FURNACES (CHAPTER 12)
• Minimise heat losses from openings on sealed units such as doors.• Use high efficiency insulating materials to reduce losses from the plant fabric.• Attempt to recover as much heat as possible from flue gases. The pre-heating of
combustion air or stock or its use in other services such as space heating is well worthconsidering.
• Reduce stock residence time to a minimum to eliminate unnecessary holding periods.• Ensure efficient combustion of fuels where applicable.• Avoid excessive pressure in controlled atmosphere units.• If maintaining stock at high temperature for long periods, consider the use of specialized
holding furnaces.• Make sure excessive cooling of furnace equipment
is not occurring.• Ensure the minimum amount of stock supporting
equipment is used.• Ensure there is effective control over furnace
operating parameters – computerized controlshould be considered for larger units.
Ta b l e o f C o n t e n t s1. INTRODUCTION ............................................................................................................................................................................................1
2. COMBUSTION ..................................................................................................................................................................................................12.1 Combustion air .........................................................................................................................................................................................1
2.1.1 Excess Air.....................................................................................................................................................................................42.1.2 Glue Gas Analysis....................................................................................................................................................................42.1.3 Determination of Excess Air ............................................................................................................................................5
2.2 Heat losses ..................................................................................................................................................................................................72.2.1 Heat loss due to incomplete combustion................................................................................................................8
3. HEAT TRANSFER ...........................................................................................................................................................................................103.1 Conduction ...............................................................................................................................................................................................103.2 Convection................................................................................................................................................................................................113.3 Radiation.....................................................................................................................................................................................................12
4.THE FUELS...................................................................................................................................................................134.1 Pipeline gas................................................................................................................................................................................................134.2 Liquid Petroleum Gas ........................................................................................................................................................................144.3 Fuel Oil ........................................................................................................................................................................................................144.4 Coal .........................................................................................................................................................................................................154.5 Choice of Fuel ........................................................................................................................................................................................16
5. COMBUSTION EQUIPMENT: OIL AND GAS BURNERS..............................................................................185.1 Gas Burners .............................................................................................................................................................................................185.2 Oil Burners ...............................................................................................................................................................................................18
5.2.1 Pressure Jet ..............................................................................................................................................................................185.2.2 Air or Steam Blast Atomiser ...............................................................................................................195.2.3 Rotary Cup ..............................................................................................................................................................................195.2.4 Low Excess Air Burners ...................................................................................................................................................19
5.3 Burner Controls ....................................................................................................................................................................................19
6. COMBUSTION EQUIPMENT: SOLID FUEL COMBUSTION .......................................................................216.1 Stokers .........................................................................................................................................................................................................216.2 Chain Grate Stoker .............................................................................................................................................................................216.3 Sprinkler Stoker.....................................................................................................................................................................................226.4 Fluidised Bed Combustion..............................................................................................................................................................22
• • • • • • • • •
7. ENERGY SAVING EQUIPMENT ........................................................................................................................................................23
7.1 Flue gas heat exchangers ................................................................................................................................................................23
7.1.1 Economiser (Feedwater heater)..................................................................................................................................26
7.1.2 Recuperator (Air heater) ................................................................................................................................................26
7.2 Accumulators ..........................................................................................................................................................................................26
7.3 Insulation ....................................................................................................................................................................................................26
7.4 O2 Analysers ............................................................................................................................................................................................27
7.5 Variable speed fan drives ................................................................................................................................................................28
7.6 Flue gas dampers ..................................................................................................................................................................................28
7.7 Waste heat boilers ..............................................................................................................................................................................28
8. POLLUTION ....................................................................................................................................................................................................29
8.1 Environmental Equipment ..............................................................................................................................................................30
8.1.1 Ash Handling Equipment ................................................................................................................................................30
8.1.2 Air Pollution Control Equipment ................................................................................................................................30
9. BOILERS ........................................................................................................................................................................................................31
9.1 Types of boilers......................................................................................................................................................................................31
9.1.1 Water Tube Boilers..............................................................................................................................................................32
9.1.2 Multi-Tubular Shell Boilers ..............................................................................................................................................34
9.1.3 Reverse Flame or Thimble Boilers..............................................................................................................................36
9.1.4 Steam generators ................................................................................................................................................................37
9.1.5 Sectional Boilers ....................................................................................................................................................................38
9.1.6 Condensing Boilers..............................................................................................................................................................39
9.1.7 Modular Boilers ....................................................................................................................................................................40
9.1.8 Composite Boilers ..............................................................................................................................................................41
9.2 Boiler system selection ....................................................................................................................................................................42
10. ENERGY AND COST SAVING FOR BOILERS ..............................................................................................43
10.1 Potential Losses ..............................................................................................................................................................................43
10.2 Boiler Energy Balance ................................................................................................................................................................43
10.3 Minimizing Boiler Losses ..........................................................................................................................................................44
10.3.1 Maintenance saving opportunities ..............................................................................................................................44
10.3.2 Blowdown Heat Loss ........................................................................................................................................................45
10.3.3 Heat Transfer ..........................................................................................................................................................................46
10.3.4 Excess Air Reduction..........................................................................................................................................................48
• • • • • • • • • • • • • •
10.3.5 Flue gas heat recovery ......................................................................................................................................................49
10.3.6 Combustion air pre-heat ................................................................................................................................................53
10.3.7 Load Scheduling ....................................................................................................................................................................54
10.3.8 On-Line Cleaning ................................................................................................................................................................56
10.3.9 Flue Shut-Off Dampers ....................................................................................................................................................56
10.3.10 Variable speed fan drives ................................................................................................................................................56
10.3.11 Integrated control ................................................................................................................................................................57
10.4 What to do first – a quick checklist ................................................................................................................................58
10.4.1 Check list ..................................................................................................................................................................................58
11.TYPES OF FURNACES ............................................................................................................................................................................59
11.1 Batch Furnaces ................................................................................................................................................................................59
11.2 Continuous Furnaces ..................................................................................................................................................................59
11.3 Direct Fired Furnaces ................................................................................................................................................................60
11.4 Indirect Heated Furnaces ........................................................................................................................................................61
12. ENERGY AND COST SAVINGS FOR FURNACES ............................................................................................................62
12.1 Potential Losses ..............................................................................................................................................................................62
12.1.1 Furnace Energy Balance....................................................................................................................................................62
12.2 Minimizing Furnace Losses ......................................................................................................................................................63
12.2.1 Flue gas heat loss..................................................................................................................................................................63
12.2.2 Heat Loss to incomplete combustion......................................................................................................................66
12.2.3 Radiation Heat Loss............................................................................................................................................................66
12.2.4 Furnace pressure control ................................................................................................................................................67
12.2.5 Furnace efficiencies and Monitoring and targeting ..........................................................................................68
12.3 What to do first – a quick checklist ................................................................................................................................69
APPENDIX ........................................................................................................................................................................................................70
Conversion Tables ................................................................................................................................................................................................70
Boiler Efficiency Test ............................................................................................................................................................................................71
Furnace Efficiency Test ........................................................................................................................................................................................83
• • • • • • • • •
1
This guide examines the energy savings potentialsfor boilers and selected furnaces. The boilersection starts with a description of differentboilers plant, combustion equipment used andfuels available. Environmental impacts aredescribed, boilers selection processes outlined andfinally a list of measures and a strategy outline forsaving energy in boiler operation.
2. COMBUSTION
• • • • • • • • •In all aspects of boilers and furnaces (includingdryers and kilns) heat is produced fromcombustion or by the use of electrical energy.Theheat is transferred to the product or water toproduce stream in the case of a boiler.
The fuel (with the exception of electricity whichheats an element) burns in the ‘combustionchamber’, which varies in shape and sizedepending on the application. Common fuelsinclude pipeline gas, liquid petroleum gas, heavyfuel oil, lighter oils and solid fuels such as biomassor coal. If gas is produced ‘on site’ this can also beused.
The in the case of a furnace the product is then
exposed directly to the heat generated in thecombustion chamber, flue gas heat or a gas/fluidthat has been heated by the combustion process.
2.1 COMBUSTION AIR
Stoichiometric air represents the amount of airrequired for complete combustion with theperfect mixing of the fuel and air Stoichiometric airis sometimes called theoretical air. If perfect mixingis achieved, every molecule of fuel and air takespart in the combustion process. Excess air must besupplied to ensure complete combustion of thefuel because perfect mixing of fuel and air doesnot occur. Percentage excess air is defined as the
The guide then moves on to savings in furnaces.Various types of furnaces and energy savingmeasures are described.The emphasis here is onsavings from excess air reduction, combustion airpreheat, correct insulation and furnace pressurecontrol.
1. INTRODUCTION
• • • • • • • • • • • • • •
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total amount of combustion air supplied in excessof the stoichiometric air, expressed as apercentage of the stoichiometric air.
Total air = Stoichiometric air x (1 % Excess Airr)Total air = Stoichiometric air (x (1 +( 100 )The minimum amount of excess air requiredvaries with the fuel used and the efficiency ofmixing the air and fuel. If less than the minimumquantity of air is supplied, some of the fuel will notburn completely and there is a waste of fuelenergy. Evidence of incomplete combustion usuallyshows up as carbon monoxide (CO) in theproducts of combustion (flue gas). A continuousgas analyser, or a manually operated Orsat, can beused to check for CO in the flue gas.
Too much air also wastes energy. The gases leavingthe furnace are hot and contain heat energy. Ifexcessive amounts of air are supplied to thefurnace, the excess will also be heated.The effecton heat losses by varying the amount of airsupplied to the furnace is shown in Figure 1. The
minimum losses occur when the amount of airsupplied is slightly greater than the“stoichiometric” amount.
The weight or volume of each element orcompound in the fuel is required to determine thestoichiometric air. It is often inconvenient todetermine stoichiometric air in this manner, as inmany instances the precise fuel analysis isunknown or varies. A more convenient methodis to determine the quantity of air per unit of heatin the fuel, i.e. kilograms of air per gigajoule of heatin the fuel as fired (kg/GJ). Expressed in thismanner, the stoichiometric air required forcommon types of fuel is almost constant. Table 1provides values for several different types of fuel,which may be used in boilers or furnaces.
It may be suspected that a supply air fan, air inletlouvers, ducting or the air flow control method isinadequate. Knowledge of the required amount offurnace combustion air enables checking theadequacy of the air supply system.The combustionair requirements can be calculated and compared
Figure 1: Zone of maximum combustion efficiency (Source:Canadian Gov.) (Energy Management Series 7. Page 4. Figure 2)
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to the capacity of the components in the airsupply system.
Combustion air can be supplied to the equipmentby natural or forced draft systems. Natural draftuses the negative pressure (draft) produced by thefurnace stack to draw combustion air into thefurnace and the resulting flue gases out of thefurnace.The most common example of this is theordinary domestic gas furnace. Natural draft isusually applied only to small furnaces with lessthan about one GJ/h heat input.
There are several disadvantages related to naturaldraft firing. The amount of combustion air drawninto the furnace cannot be controlled accuratelyand the fuel and air mixing is inefficient.This meansthat higher levels of excess air must be maintainedto ensure that complete combustion is achievedunder all conditions.The furnace pressure is alwaysnegative which allows air to leak into the furnace,and create additional flue gas volume and heatlosses.
Forced draft firing uses a fan to supply combustionair to the equipment. Airflow is regulated bymeans of dampers so that accurate control of theproportion of air to fuel for various firing rates ispossible. A common method used to achieve this
is to operate the fuel valve and the damper with acommon mechanical linkage. Some form of
adjustable cam is used to vary the relative positions of the fuel valve and damper to provideproper fuel/air ratios at all firing rates.
The combustion air fan also provides bettermixing of the fuel and the air. The air is introducedinto the furnace around the burner(s) and vanes,which produce a swirling motion in the air as itenters the furnace, can create turbulence. A high-pressure drop between the air supply and thefurnace is required to produce turbulence, and thiscan only be achieved with a forced draft system.These advantages mean that the excess air for aforced draft system can be lower than for naturaldraft firing, with resulting lower heat losses to theflue gas.
Forced draft firing permits a slightly positivefurnace pressure at all times. Leaks will then befrom the furnace outwards, which may lead to adangerous situation when a furnace door isopened. Therefore, it is desirable to controlfurnace pressure at a slight positive value of notmore than about 10 Pa.This is normally achievedby regulating a damper in the breeching betweenthe furnace flue gas exit and the base of the stack.
Example: Combustion air requirements for a furnace using 700 l/h of Number 6 fuel oil, at 15 per centexcess air can be calculated. From Table 1, theoretical combustion air is 327 kg/GJ.The heating value of fueloil with 2.5 per cent sulphur is about 42.3 MJ/L (sulphur content can usually be obtained from the fuelsupplier).
Combustion air requirement = 700L/h x 42.3 MJ / L x 327 kg / GJ x 1.15Combustion air requirement =Combustion air requirement = 1000 MJ / GJ
= 11135 kg/h
11135 kg/hor
1.204 kg / m3
= 9248 m3/h at standard conditions.
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It may not be possible to maintain furnacepressure as low as desired if heat recoveryequipment is installed in the flue gas system or ifthe stack provides insufficient draft.
2.1.1 EXCESS AIR
The actual percentage of excess air supplied tothe furnace is one of the most informative itemsof information to the furnace operator.The mostaccurate way of determining this is to analyse theflue gas leaving the furnace.
2.1.2 FLUE GAS ANALYSIS
A furnace in which heat is produced by thecombustion of fuel can be considered to have fueland combustion air as inputs, and flue gas as theoutput (Figure 2). Practically all fuels used infurnaces are hydrocarbons, which contain theelements hydrogen and carbon. Although somefuels contain other constituents they are notusually important to the combustion process.Thehydrogen in the fuel burns to form water vapour,and the carbon burns to form carbon dioxide(CO2), or a mixture of carbon dioxide and carbon
monoxide (CO).Air contains nitrogen (N2) as wellas oxygen (O2).The N2 does not take part in thecombustion process, except for the formation ofsmall quantities of nitrogen oxides (NOx).
The major constituents of the products ofcombustion are water vapour, CO2, CO, N2, andany excess O2 left over from the combustionprocess. Not all of the constituents will be presentin all instances. The presence of CO indicatesincomplete combustion.
Flue gas analysis can be determined by the use of
a continuous analyser or by periodic sampling.Thesample should be taken as close to the furnaceexit as possible to reduce air infiltration errors.Some continuous analysers measure O2 contentand record or indicate the results. Othercontinuous analysers measure the combustiblescontent of the flue gas, which is mostly CO butmay also include some unburned fuel in gaseousform. If a continuous flue gas analyser is notavailable, a sample of the flue gas can be taken andanalysed with the use of an Orsat. The Orsatdetermines the percentage by volume of O2, CO2,and CO in the flue gas. The remaining gas isassumed to be N2, plus a small quantity of water
Figure 2: Combustion process. (Source: Canadian Gov.) (Energy Management Series 7.Page 6. Figure 3)
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vapour, which did not condense out of the sample.There are other manually operated analysersavailable, which measure either CO2 or O2 in theflue gas.These are simpler to use and can be usefulas a cross check against an Orsat.
2.1.3 DETERMINATION OF EXCESS
AIR
Flue gas analysis provides sufficient data tocalculate the excess air to the furnace. In mostfurnaces, CO is absent or very low because of highlevels of excess air. For natural gas or fuel oil firingwith no CO in the flue gas, the per cent excess aircan be determined from Figure 3. If other fuels areused or if CO is present, the following equationcan be used:
% Excess air = O2 – 0.5CO% Excess air = x 100% Excess air = 0.2682N2 – (O2 – 0.5CO)
Where O2 = oxygen by volume in flue gas (%)CO = carbon monoxide by volume (%)N2 = nitrogen by volume (%)
Examples: The flue gas analysis by volume on afurnace burning natural gas gives the followingresults:O2 = 9.8%CO2 = 6.2%CO = 0%
From Figure 3, excess air is approximately 79 percent. This number can be compared to thefollowing calculation.
%N2 = 100% - (9.8% + 6.2% + 0%)= 84%
Figure 3: Excess air versus flue gas analysis. (Source: Canadian Gov.) (Energy Management Series 7.Page 7. Figure 4)
6
% Excess Air = 9.8 – (0.5 x 0)% Excess Air = x 100% Excess Air = (0.2682 x 84) – [9.8 – (0.5 x 0)]
= 77%
This value is very high for a furnace burningnatural gas, and the possibility of reducing theexcess air level should be investigated.
Another example will provide greater familiaritywith the calculation procedures. A furnace isburning coke-oven gas with the following flue gasanalysis.
O2 = 2.1%CO2 = 10%CO = 0%N2 = 87.9% (by difference)
The equation should be used to calculate theexcess air since Figure 3 is not applicable for coke-oven gas.
% Excess Air = 2.1 – (0.5 x 0)% Excess Air = x 100% Excess Air = (0.2682 x 87.9) – [2.1 – (0.5 x 0)]
= 9.8%
This excess air is quite acceptable for a furnaceburning coke-oven gas.
In a furnace burning natural gas with a deficiencyof air, the flue gas analysis is as follows.
O2 = 0%CO2 = 11%CO = 2%N2 = 87% (by difference)
Figure 3 cannot be used because of the presenceof CO.
% Excess Air = 01 – (0.5 x 2)% Excess Air = x 100% Excess Air = (0.2682 x 87) – [0 – (0.5 x 2)]
= – 4.1%
Table 1: Combustion Air Requirements
Fuel Stoichiometric Air Typical Excess Air Total Air kg/GJ Askg/GJ As Fired (minimum as a %) Fired
Natural Gas 318 5 334
#2 Fuel Oil 323 10 355
#6 Fuel Oil 327 10 360
Coke-oven Gas 1 295 15 340
Refinery Gas 2 312 10 343
Propane 314 5 330
CO 12%
H2 42%
CH4 37%
C2H4 and higher 5%
CO2 Remainder
1Analysis by volume CH4 31%
C2H6 20%
C3H8 38%
H2 5.6%
C4H10 and higher 1.0%
Inert Gases Remainder
2Analysis by volume
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This means that approximately 4 per cent lessthan the theoretical air required for completecombustion is being supplied to the burners. If thetype of process permits it, increasing thecombustion air supply should reduce the carbonmonoxide.
Occasionally, CO occurs with high O2. This isusually an indication of poor mixing of the fuel andcombustion air. Sometimes improvements can bemade by adjusting the burner air dampers tocreate more turbulence where the fuel and airmix. In other instances it may be necessary toreplace the burner assembly.
2.2 HEAT LOSSES
The heat discharged from the stack, is usually thelargest loss in a fuel fired boiler or furnace. Flue gasanalysis and flue gas temperature can be used tocalculate the loss. If there is no heat recoveryequipment on the furnace or boiler, thesemeasurements should be taken at the outlet tominimize the possibility of the readings being
affected by air infiltration. With heat recoveryequipment the readings should be takenimmediately downstream of the equipment.
The flue gas heat loss has four components, whichcan be calculated separately.
• Dry gas heat loss.• Heat loss from the water vapour
contained in the combustion air1.
• Heat loss from the water vapourproduced by the combustion of thehydrogen in the fuel
2.
• Heat loss from the water vapourproduced by the evaporation of moisturein the fuel
3.
For natural gas and oil, the moisture in the fuel isminimal, and the evaporation of the moisture heatloss can be ignored.The values for flue gas lossescan be calculated using figures from the appendix,which gives a boiler efficiency test. Figure 4 belowshows this graphically for fuel oil.
1 This is often very small and is a function of atmospheric humidity.2 This quantity is a function of the fuel and therefore cannot be changed by
operation. It is therefore not included in this discussion.3 As above this quantity is primarily a function of the fuel and therefore cannot
be changed by operation. It is therefore not included in this discussion.
•
Figure 4: Flue-gas loss for fuel oil. (Source: Canadian Gov.) (Energy Management Series 6.Page 12. Figure 10)
8
In practice this loss can vary from 8% to 50%depending on the fuel. The major influencingfactors are the exit flue gas temperature and thedegree of excess air present.To minimize losses incoal-fired plant, correct combustion is essentialincluding better fuel preparation, better stokingpractices and improved control of combustion air– both the undergrate and the overgrate draughts.The same factors apply to oil-fired boilers. Fuelpreparation should be correct (uncontaminatedand at the right temperature), burners undamagedand properly maintained, and combustion air(both primary and secondary) should beintroduced at the right rate and with adequateturbulence.
For fuels such as coal, biomass, and industrial wasteor municipal refuse, the heat loss from themoisture in the fuel can be considerable. Wood,for instance, could have a moisture content of upto 60 per cent, depending on the source andcapability of the wood burning equipment. Figure5 shows the variations in the moisture heat lossfor a typical biomass fuel having different moisturecontents at a flue gas temperature of 200 ºC. At
30 per cent moisture, this fuel heat loss is 5.5 percent of the fuel heat content. At 60 per centmoisture, the loss increases to 21 per cent.
2.2.1 HEAT LOSS DUE TO
INCOMPLETE COMBUSTION
Heat can also be ‘lost’ by the incompletecombustion of fuel, this is indicated by thepresence of CO and, in the case of coal,combustible material left in the ash.
2.2.1.1 HEAT LOSS TO CO
By controlling the amount of dark smokeproduced, the level of CO can be kept to apractical minimum. The three influencing factorsare insufficient combustion air, inadequate fuel/airmixing, or the ingress of cold air ‘freezing’ thecombustion reaction. The heat loss, which ismeasured in terms of the non-conversion of
Figure 5: Flue-gas loss with moisture content for biomass fuel. (Source: Canadian Gov.)(Energy Management Series 6. Page 13. Figure 11)
9
carbon into carbon dioxide, is relatively small, butthe rapid fouling of heat transfer surfaces underthese conditions adversely influences the boiler’sperformance.
2.2.1.2 HEAT LOSS TO
COMBUSTIBLES IN THE ASH
(COAL APPLIANCES)
This loss generally varies from 2% to 5%. It is aclear indication of combustion air starvation forwhich there are three possible causes: poor airdistribution under the grate: too thick a fire bed: oruneven bed thickness resulting from poor stokingpractices.
The unburned combustibles heat loss is notsignificant for properly operating oil and gas firedinstallations, but it can be for solid fuel units. Figure1 demonstrates that there could be a minorunburned fuel loss at the maximum efficiencypoint, but the real significance of this figure is that
the losses increase very rapidly as the total air isdecreased. The measure of this condition isreflected by the presence of significantcombustibles in the flue gas.
In coal, biomass and other solid fuels, unburnedcombustible material will be found in the refusecollected in the ash pit and the fly ash hopper.Theloss should be determined when the boiler istested for efficiency.To do so requires a method ofcollecting and weighing the refuse undercontrolled conditions and laboratory testing therefuse for its HHV. The loss can be calculated asshown.
Unburned combustible heat loss = Dry refusequantity x Refuse heat content
Where units are:
Heat loss (MJ/kg fuel as-fired)Dry refuse (kg of refuse/kg of as-fired fuel)Refuse heat content (MJ/kg of refuse)
• • • • • • • • •
The transfer of heat from the burner flame to theproduct can be by conduction, convection, orradiation, and in most instances a combination ofall three.
3.1 CONDUCTION
Heat transfer to the product by conduction is onlysignificant in indirect heated equipment, where theproduct is isolated from the flame by a heatexchange surface. Muffle furnaces and furnacesusing radiant tube heaters (Figure 6) are examplesof indirect heating arrangements. Heat conducted
through a solid can be calculated.Q = k x A x �T x 3.6
Q =Q = t
Where, Q = Heat conducted (kJ/h)k = Thermal conductivity of solid
[W/(m·ºC)]A = Surface area (m
2)
�T = Mean temperature differen-tial across solid (ºC)
T = Thickness of solid (m)3.6 = Conversion factor from watts
to kilojoules per hour.The foregoing equation shows that rate of heattransfer increases in proportion to surface area,and to temperature differential across the solid,and is inversely proportional to material thickness.
3. HEAT TRANSFER
• • • • • • • • • • • • • •
•
Figure 6: Radiant Tube Gas-Fired Rotary Furnace. (Source: Canadian Gov.)(Energy Management Series 7. Page 13. Figure 7)
10
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Example: A muffle furnace has a 10 mm thick, high nickel steel enclosure with a surface area of 55 m2.
Useful heat to the product, all of which is transmitted through the wall, is 1.9 GJ/h.The thermal conductivityof high nickel steel is 31 W/(m·ºC).The temperature drop through the muffle wall can be determined asfollows:
Heat Conducted = 31W / (m·ºC) x 55m2x DT x 3.6
Heat Conducted =Heat Conducted = 0.01 mHeat conducted is 1.9 GJ/h, or 1.9 x 10
6kJ/h
Rearranging the equation,
�T = 1.9 X 106X 0.01
�T =�T = 31 X 55 X 3.6
= 3.1ºC
The temperature drop across the enclosure is 3.1ºC at the specified rate of heat transfer.
•surface increases, but not proportionally. Thefollowing equation can be used for gases:
Q = 23.46 x A x �T x V0.78
x d
Where, Q = Rate of convection heat transfer(KJ/h)
A = Area of heat transfer (m2)
�T = Temperature differential betweensolid and fluid (ºC)
V = Fluid velocity (m/s)d = Gas density (kg/m
3)
3.2 CONVECTION
Heat transfer by convection takes place at theboundary between a solid wall and a gas or liquid.Intermingling takes place between the stagnantlayer of fluid at the wall and the moving fluidstream next to the stagnant layer.Tests on rate ofheat transfer by convection show that the rate isproportional to surface area and temperaturedifferential between the solid and the fluid. It alsoincreases as the velocity of the fluid over the wall
Example: A furnace is 3 metres long and has a 1 metre by 1 metre cross-section. Flue gas flows throughthe furnace at an average velocity of 0.5 m/s with a gas temperature of 500ºC.The temperature differentialbetween the furnace walls and the flue gas averages 150ºC. For most practical purposes, the density of aircan be used for flue gas. From standard references, the density of air at 500ºC is 0.458 kg/m
3.The average
rate of heat transfer by convection to the walls, floor and roof can be determined as follows.
Furnace area swept by flue gas = (1 + 1 + 1 + 1) m x 3m= 12 m
2
�Q = 23.46 x 12m2x 150ºC x (0.5m/s)
0.78x 0.458kg/m
3
= 11 263 kJ/h
12
3.3 RADIATION
Heat transfer by radiation becomes significant fortemperatures above 600ºC. A hot body emitsradiation in the form of heat, which can bereceived by another solid body in the path of heatradiation. In an electric furnace or boiler, the wallsor tank, which are heated by the electrodes, emitheat radiation to the furnace contents.
The amount of heat radiated from a solid body isproportional to the fourth power of its absolutetemperature, and directly proportional to itsemissivity. Absolute temperature is the number ofdegrees above absolute zero and is measured inKelvin (K), which is equivalent to degrees Celsiusplus 273.
Emissivity is a measure of the heat radiated froman object compared to that radiated from a similarsized “black body” at the same temperature. Themaximum value of emissivity is that of the “blackbody’; which is 1. Typical emissivity values forfurnace walls and oxidized steel are 0.8 to 0.9.Because both the hot body, (the furnace wall) andthe cooler body, (the furnace contents) areemitting radiation, the net total heat received bythe contents is the difference between the heat
emissions of the two bodies. The equation for afurnace is:
Q = K x F x [( T14– ( T2
4]
Q = K x F xQ = K x F x [(100) (100) ]
Where, Q = Rate of radiation heat transfer(kJ/h)
K = “Black body” coefficient (20.6)F = Overall radiation factor
depending on emissivity andsurface areas of the furnacewalls and contents
T1,T2 = Absolute temperature of hotand colder bodies respec-tively (K)
F = A1
F =F = 1 + ( A1 ) ( 1 – 1)F = 1 + ( A1 ) ( 1 – 1 F = e1 + ( A2)( e2 – 1 )
Where, A1 = Surface area of furnacecontents exposed to walls(m
2)
A2 = Surface area of furnace walls(m
2)
e1
= Emissivity of furnace contentse
2= Emissivity of furnace walls
•
Example: A furnace with a square cross section of 1 metre by 1 metre is heating carbon steel billets100mm by 100mm.The furnace wall temperature is 1000ºC.The furnace floor does not radiate heat. FromTable 3, the emissivity of a fireclay brick furnace wall is 0.75, and the emissivity of oxidized carbon steel is0.80.The heat input to the billet per metre of length when the steel is heated to 650ºC can be calculated.
A1 = (0.1 + 0.1 + 0.1) x 1= 0.3m
2
A2 = (1 + 1+1) x 1= 3m
2
F = 0.3F =F = 1 + ( 0.3 ) ( 1 – 1)F = 1 + ( A1 ) ( 1 – 1 F = 0.8 + ( 3 )( 0.75 – 1 )
= 0.234T1 = 1000ºC + 273
= 1273KT2 = 650ºC + 273
= 923K
13
Heat radiated/metre lengthQ = K x F x [( 1273
4– ( 923
4]
= 20.6 x 0.234 xQ = K x F x [( 100 ) (100 ) ]
= 91 604 kJ/h
Radiation also takes place from hot gases to thefurnace contents. This method of heat transferdoes not follow the same laws as the radiationfrom solid bodies. Radiation from a luminous flameis higher than from a clear flame of hot gases.
• • • • • • • • •
4. the fuels
• • • • • • • • • • • • • •Each conventional fuel differs from the others inits combustion characteristics, and this influencesheat transfer. Fuels may be solid, liquid or gaseous,and either ‘commercial’ or ‘waste’. Commercialfuels are fossil fuels, which are extracted,treated/refined to varying degree and soldnationwide by organizations such as oil companies.Waste fuels are by-products or adjuncts ofprocessing or domestic activities and are,obviously, only economically available locally.
Factors other than simple conversion to heat mustalso be considered, including those relating to: thestorage and handling of the fuels, maintenance,environmental impact etc. All of these influencethe overall efficiency and true cost of burning afuel.
4.1 PIPELINE GAS
Because gas mixes so readily with air and burnswithout producing smoke and soot, boiler and
furnace maintenance costs are low. Natural gasburners tend to be simpler with fewer mechanicalparts and are also therefore cheaper to maintain.
Natural gas would normally be the preferred fuelfor burning in boiler plant if convenience alone isconsidered. It does not have to be stored; incommon with all the gaseous hydrocarbons itmixes readily with combustion air to burn clearly;and, ideally, the products of combustion are justwater and carbon dioxide. These basic argumentswould seem to carry a great deal of weight becauseglobally the majority of new boiler and furnaceinstallations in recent years have been gas tired.
The availability of an adequate gas supply atindividual sites needs to be checked in advance aslocal constraints in the distribution system cansometimes lead to delays in providing aconnection. A second factor is safety. Complyingwith legislation regarding the supply and use of gasinvolves some specialised equipment that has tobe maintained.
•
14
Thirdly, burning gas does cause pollution. Whilethe pollutants do not include smoke or noxioussubstances, they do include gases that contributeto the so-called greenhouse effect. Gas, beingcomposed predominantly of methane, is in itselfone such gas. Carbon dioxide, which is producedby the combustion of all fuels, is another: itsproduction is not only unavoidable but alsodesirable as its presence indicates completecombustion of the gas. However, pipeline gas alsoproduces oxides of nitrogen (NOx). This isbecause the gas burns at high temperatures andthis provides the additional energy necessary tomake the oxygen and nitrogen in the air combine.
As regards the pricing of gas, the actual price thata customer will pay, as for any fuel, depends on theamount used and the type of supply, and can varyover a wide range. Prices are generally competitivewith oil products, for example with gas oil for firmgas supplies and with heavy fuel oil forinterruptible supplies. Continued plant operationduring interruptions of an interruptible supplyrequires a boiler to be dual-fuel fired usually withoil as an alternative. In firing these two fuels theburner would normally be set to achieve the mosteffective results on gas, because gas is used formost of the year, with oil firing only on the fewdays of interruption sometimes experienced.
4.2 LIQUID PETROLEUM GAS
Liquid Petroleum Gas (LPG) is used to describetwo fuels: propane and butane. In practice the vastmajority of installations use propane. All thegeneral comments about natural gas apply equallyto LPG.
One major difference between the two fuels isthat LPG requires both storage facilities and thespecial precautions needed in relation to leakages.The first can be very significant in terms of boththe capital cost of a project and its overall
operational and maintenance costs. The storagetanks involved are pressure vessels and thereforesubject to both annual and long-term inspectionand testing. If a customer owns his own tanks he isresponsible for carrying out all inspections andtests at his own expense. In practice, manycustomers lease or rent the tanks from the fuelsuppliers, eliminating both this responsibility andalso that of general maintenance.
The second major difference is that LPG is heavierthan air. If natural gas, which is lighter than air,escapes, all sources of ignition should be removedand windows opened: it will then dispersenaturally. LPG, on the other hand, may find its waydown into pipe ducts, cable tunnels, drains, cellarsetc., and will not disperse unless forced to using afan. This characteristic influences the location ofstorage tanks in relation to buildings, hollows,drains, cellars etc. and plant location may beaffected.
4.3 FUEL OIL
Crude oil is a complex mixture of hydrocarbons.The other fuel users mainly require the lighterfuels – petrol, kerosene, diesel, oil, gas oil etc.This‘end of the barrel’ also provides the mainfeedstock requirement for the petrochemicals andplastics industries. However, the primaryseparation of oil provides mainly the heavier moreviscous fuel oils, which potentially cause problemsin storage, handling, combustion andenvironmental pollution.The main advance of fueloil, on the other hand, derives from the fact thatthese heavier fractions tend to be cheaper.
Problems relating to fuel oil storage include boththe capital cost of the storage tanks and theproblem of handling the oil. Fuel oils are viscousliquids, which become thicker and moreintransigent the colder they become. Gas oil, thelightest and least viscous of the fuels, will usuallyremain in liquid form no matter how cold the
•
•
15
winter. This either allows it to flow under gravityfrom the tank to the burner or enables it to beeasily pumped. This holds true unless prolongedperiods of cold weather occur where thetemperature remains below freezing for a week ormore. Under these conditions, some of the waxescontained in the oil begin to alter into sticky solids.Typically, these solids build up on the filters in theburner supply line, eventually blocking them.Although this is an infrequent occurrence, someexposed sites have installed electric trace heatingon the filters and/or the external distributionpipework as a precaution.
The heavier grades of oil require heating in orderto remove them from the tank at all.To reduce theamount of energy required for pumping the oil tothe burners, an appropriate pumping temperatureshould be maintained.
Table 2 shows the recommended minimumstorage temperatures for the different grades ofoil and also the minimum temperatures foroptimising pumping costs.The temperatures givenin this table, especially for the heaviest oils are onlymeant as an indication. With the exception of gasoil, the general trend is for the heavier and moreviscous oil grades to require higher storage andpumping temperatures.
The oil is heated either electrically or by takingsteam from the boiler, thereby reducing its overall
efficiency. The uncontrolled overheating of oil canbe very expensive, and uninsulated or poorlyinsulated tanks or pipes are also a major waster ofenergy.
Considerable energy is wasted if all the oil in atank is heated to the required pumpingtemperature, and it is also bad practice to havetoo much hot oil circulating and not being used bythe burners. A well designed hot oil ring maincirculates sufficient oil plus about 10% in order tomeet the maximum demand for all the burners itserves. Fresh oil is drawn from the storage tank asrequired, but the storage tank never forms part ofthe basic circulation system thereby allowing allthe oil to heat up to the pumping temperature.This ensures that both the size and the capital andrunning costs of the oil heaters are kept to apractical minimum.
The penalty of this oil heating requirement is thatit is uneconomic to use these heavier grades offuel oil on small boiler plant. Below 3 MW heavyoil would be inefficient and, for bunker oil, 20 MWis probably the lower limit. However, the marketprice for the heavier fuel oils over recent years hasencouraged their greater use.
Provided that a grade of fuel oil is delivered to theburner in good condition and at the correcttemperature for the burner, the production ofsmoke or carbon monoxide should be minimal.
Table 2: Recommended Minimum Storage Temperatures for Different Grades of Oil
Fuel Oil Grade Viscosity Minimum Storage Typical PumpingType * *Cst @ 100ºC Temperature ºC Temperature ºC
Gas/Oil D 1.0 None stated None stated
Light E 8.2 10 10-12
Medium F 20.0 25 30-35
Heavy G 40.0 40 55-60
Bunker H 56.0 45 70
* Refers to BS 2869 - 1986.
16
The fact that all fuel oils contain some sulphurmeans that sulphur oxides (SOx) are producedduring combustion. Such gases are nowconsidered to contribute to the global pollutionproblem. Oil, however, burns at a lowertemperature than the gaseous fuels and thereforeproduces less NOx gases.
4.4 COAL
The clean burning of solid fuels presents aproblem because the air required for combustionis less readily available to the mass of fuel,compared with atomised liquid fuels and gas. As aresult, coal burning has been responsible for mostof the traditional forms of air pollution – smoke,soot, grit and dust. Modern coal plant usingmicroprocessor control, on boilers with improvedstoker design, has eliminated this problem.Stringent control of SOx and particulates can beachieved through the use of limestone injection,cyclones and bag filters.
Throughout the sub-tropical and temperateregions of the world coal deposits are generallysignificantly larger than crude oil or natural gasdeposits. As crude oil prices have risen, many oil-importing countries with significant coal depositshave undertaken considerable research into coalburning and, in some cases, have implementedpolicy decisions promoting the use of coal forboiler firing.
Coal is the cheapest of the available conventionalfuels. Furthermore, coal prices tend to be morestable than prices for other fuels, and long-termprice contracts with only moderate built-inincreases are available.
A coal-fired plant does, however, incur highercapital and operating costs.As well as the boiler or
furnace plant itself, the capital cost incurredincludes bunkerage, coal handling equipment, andfacilities for ash removal, handling and storage.Operational costs are high because, despiteconsiderable development efforts by plantmanufacturers to reduce the labour component, itis rare that coal fired plants are ever fullyautomated and unmanned.
Maintenance costs are also significantly higher thanfor the other fossil fuel. The difficulty of achievingclean combustion means that the boilers requiremore frequent cleaning. Both the fuel and the ashare very hard and abrasive so levels of wear andtear on coal and ash handling equipment are high.
The disposal of ash in a manner that avoidspollution is a significant operational componentand, in some regions of the country, can be a costlybusiness.
Low combustion temperatures limit pollutionfrom NOx, but the SOx released by coalcombustion must be considered. Both the calorificvalue and the sulphur content of coal vary fromsource to source.The average South African coalsold into the industrial market has low sulphurcontent and is less polluting than the heavier fueloils.
4.5 CHOICE OF FUEL
The choice of fuel is not a simple matter. It involvesbalancing a number of factors including the capitalcost of the plant, the price of the fuel, andoperating and maintenance costs. Someconsideration should also be given to likely futurechanges in fuel and pricing policies and topollution control legislation.
•
•
17
Table 5 summarises those advantages anddisadvantages that can be estimated and quantifiedfor each fuel.
Table 4: Calorific values of Some Fuels
Fuel Calorific ValueMJ/Unit
Gas
Natural Gas 38.0/cu m
LPG Propane 50.0/kg
LPG Butane 49.3/kg
Fuel Oil
Gas Oil 38.0/liter
Heavy Oil 41.0/litre
Coal 29.0/kg
Table 5:The pros and cons of various fuels.
COAL FUEL OIL NATURAL GAS LPGDisadvantages Disadvantages Disadvantages Disadvantages
Capital Capital Cost For: Capital Cost For:Cost For:
Tanks Storage Tank (orBunkerage leased)
InsulationFuel Handling
Heavy Fuel OilAsh Handling
Running Cost For: Running Cost For: Running Cost For:
Tank Heating Fuel (Especially for Small Fuel CostInstallations)
Heavy Fuel OilInterrupt TariffHeavy Oil as Second Fuel
Maintenance Maintenance Costs Maintanance Costs For: Maintenance CostsCosts For: For: For:
Safety Equipment Safety EquipmentWear from Abrasive Boiler/FurnaceFuel & Ash Cleaning
Boiler Cleaning Burners
Environmental Costs: Environmental Environmental Costs: EnvironmentalCosts: Cost:
Smoke Emission High NOx
Smoke Emission High NOx
Grit & Dust EmissionSulphur Emission
Sulphur EmissionClean up Heavy Fuel Oil
Ash Disposal Cost Higher NOx
Adva
ntag
es
Adva
ntag
es
Adva
ntag
es
Adva
ntag
es
Low
Cost
Chea
per T
han
Gas
No
Stor
age
No
Sulph
ur
No
Sulph
ur
18
In order to ensure the proper mixing of fuels withcombustion air and the correct flame shape, formaximum heat transfer from the flame to thewater/steam or heated product, specializedequipment is used. The type of equipment isdependent on the furnace/boiler conditions andthe fuel or fuels of choice. (Boilers and furnacescan be set up to fire more than one fuel.)
5.1 GAS BURNERS
Apart from the safety requirements in theirdesign, gas burners are essentially simple. Verysmall boilers use a simple atmospheric burner,which entrains its combustion air from itssurroundings. However, as the air and gas are notforced to mix, surplus air is required to ensurecomplete combustion. This surplus is heated andthen passes out via the flue, thereby reducingboiler efficiency.
A larger boiler with a fully enclosed combustionchamber needs a burner that will force the air andgas to mix thereby controlling the length andshape of the flame.The quantity of combustion aircan be precisely controlled to maximisecombustion efficiency.
Natural gas mixes readily with air.The ring-type gasburner consists of a circular barrel ringed withmultiple outlet ports. The “spud” type burnerconsists of a ring of 4 to 8 single barrels, each witha widened end containing multiple outlet ports. Ineither case the register surrounds the barrels withair.
Many boilers are equipped with combinationnatural gas and oil burners with the second fuelused as back up for the prime fuel.
5.2 OIL BURNERS
Oil burners are more complicated because thefuel has to be in the right condition for clean andrapid combustion. This entails atomising the oilinto small droplets of the correct size, which canonly be done if the oil is at the right temperatureand therefore the right viscosity. At too low atemperature the droplets are too big: combustionis poor and produces soot and smoke.At too higha temperature the droplets can be too small,passing through the flame too rapidly to burn. Inneither case is the full energy content of the fuelbeing used: furthermore, the heat transfer surfacesbecome fouled.
Oil burners are of three basic types.The simplestand most widely used is the pressure jet wherethe oil is pumped at pressure through a nozzle.The air or steam blast type uses gas pressure toshatter the oil into droplets, while the Rotary Cupuses centrifugal force to break the oil up. Eachtype of burner has its benefits and disadvantages.
5.2.1 PRESSURE JET
Advantages:• Very simple in construction and cheap to
replace.• Comes in many sizes to suit most
applications.
5. combustion equipment: oil andgas burners
• • • • • • • • •
•
•
19
• Can produce all flame shapes from ‘longand thin’ to ‘short and fat’ so can fit alltypes of boiler or furnace combustionchamber.
Disadvantages:• Prone to clogging by dirty oil so needs
fine filtration.• Limited turndown ratio of only 2:1.• Easily damaged during cleaning.• Highest oil pre-heat temperature requi-
red for atomisation.
5.2.2 AIR OR STEAM BLAST
ATOMISER
Advantages:• Very robust in construction.• Good turndown ratio of 4:1.• Good control of the combustion air/fuel
over the whole firing range.• Good combustion of the heavier fuel oils.
Disadvantages:• Energy used either as compressed air or
as steam for atomisation.
5.2.3 ROTARY CUP
Advantages:• Good turndown ratio of better than 4:1.• Good atomisation of heavy fuel oils.• Lowest oil pre-heat temperature required
for atomisation.
Disadvantages:• Most complex and costly to maintain.• Electrical consumption required for the
cup drive.
Oil and gas burners produced or sold in this
country have to meet statutory safety andemission standards.
5.2.4 LOW EXCESS AIR BURNERS
Standard natural gas and oil burners operate at 10to 15 per cent excess air at full capacity and higherexcess values at lower firing rates. The increasingexcess air with decreasing firing rate phenomenonresults from burner registers, which are fixed atsettings that provide best results at full capacity.Low excess air burners permit operation at 2 to 5per cent excess air. A reduction of excess air from15 to 5 per cent would reduce fuel costs byalmost 1 per cent.These savings result from highercost features as follows:
• Better design of the air diffusers, airregister, and burner, which achieve bettermixing and combustion.
• Burner registers which are modulatedwith the tiring rate to provide bettercombustion at firing rates below 100 percent.
5.3 BURNER CONTROLS
In conjunction with the choice of burner type,consideration must be given to the control systemrequired. The simplest ON/OFF control meanseither that the burner is firing at full rate or that itis off.The major disadvantage with this method ofcontrol is that the boiler is subject to large andoften frequent thermal shocks every time theboiler tires. Its use is therefore limited to smallboilers with an output up to 300 kW.
Slightly more complex is the HIGH/LOW/OFFsystem where the burner has two firing rates.Theburner operates first at the lower tiring rate andthen switches to full firing as needed, therebyovercoming the worst of the thermal shock. The
•
20
burner can also revert to the low-fire position atreduced loads, again limiting thermal stresseswithin the boiler. Typically this type of system isfitted to boilers with an output of up to 3.5 MW.
A modulating burner control will alter the firing rateto match the boiler load over the whole turndownratio. Every time a burner shuts down and restarts,the system must be purged by blowing cold airthrough the boiler passages: this wastes energy andreduces efficiency. Full modulation, however, meansthat the boiler keeps firing, and fuel and air arecarefully matched over the whole firing range tomaximise thermal efficiency and minimise thermalstresses.Typically this type of control can be fitted toboilers above 1 MW.
In matching a burner and a control system to aboiler three factors must be taken intoconsideration.
• The maximum output of the plant:• Whether the load is steady or fluctuating:• The fuel being used.
An ON/OFF control, for instance, is not suitablefor heavy fuel oil
The basic choices as they relate to oil burners aresummarised in Figure 7. There is always someoverlap between burner types and control systemtypes but the preferred combinations are outlined.
Figure 7:Type of fuel oil with recommended burners and controls. (Source: ETSU)(Good Practice Guide 30. Page 67. Figure 38.)
21
Because carbon burns fairly slowly and coal needsto be in the combustion chamber for a relativelylong period for the air to reach it and causecomplete combustion, many forms of stoker (fortransferring coal to the grate) have beendeveloped. Some have experienced periods ofpopularity and have now declined, while othershave stood the test of time.
Coals from different pits or washeries can havevery different combustion properties.Furthermore, coals from the same pit that havebeen stocked for long periods are very differentfrom newly mined coal. As a result a boilercombustion system must be regularly adjusted tomaximise energy conversion. In the followingsection only those types of stoker that would befitted to a boiler with an output of 1.5 MW andabove are considered. Below this level there islimited choice: each boiler comes with its ownproprietary form of stoker, screw feeding the coaleither onto the top of the fire or pushing it upfrom below.
Three basic types of stoking system are commonlyused with the larger boilers - two of themtraditional designs and one a relatively moderndevelopment.
6.1 STOKERS
Stokers are mechanical devices that burn solid fuelin a bed at the bottom of a combustion chamber.They are designed to permit continuous orintermittent fuel feed, fuel ignition, adequatesupply of combustion air, release of gaseousproducts, and disposal of ash.
Stokers are classified according to the manner inwhich the fuel reaches the fuel bed. In an underfedstoker, the fuel and air enter the burning zonefrom beneath the bed. Overfed stokers have thefuel entering the combustion zone from above, inthe opposite direction to the airflow. Thespreader-type overfeed stoker delivers fuel so thata portion burns in suspension while the remainderfalls and burns on the moving grate.
6.2 CHAIN GRATE STOKER
The chain grate stoker has for many years beenthe most widely used method for firing coal onmedium sized industrial and commercial boilers,even though it is relatively expensive to buy,operate and maintain. To reduce operating costsequipment manufacturers are working to developa fully automatic system requiring little or nointervention from trained operators.
The coal is fed onto one end of a moving steelbelt. As the belt moves along the length of thefurnace, the coal burns before dropping off theend as ash. Some degree of skill is required,particularly when setting up the grate, air dampersand baffles, to ensure clean combustion leaving theminimum of unburnt carbon in the ash and toachieve maximum heat transfer in the furnacechamber.
This type of stoker will only operate effectivelyusing certain types and qualities of coal. Coal mustbe uniform in size, as large lumps will not burn outcompletely by the time they reach the cod of thegrate. Furthermore, small pieces or ‘fines’ mayblock the air passages in the grate and make it
6. combustion equipment:solid fuel combustion
• • • • • • • • •
•
•
22
more difficult for combustion air to reach the coal.The grate also relies on having a layer of ash ontop of it to protect it from the highesttemperatures of the burning coal, so using coalswith a very low ash content will result in rapidgrate damage.
6.3 SPRINKLER STOKER
The sprinkler stoker is an original mechanicalstoker system, which has been brought up to date.The principle is to spread fresh coal on top of analready, burning firebed. Once the system has beenset up to spread this coal evenly it is simple tooperate and has many fewer mechanical parts tomaintain than the chain grate stoker.
Many units of this type have been manufacturedwith control systems very similar to those for gasor oil-fired boilers. Fuel feed rate and combustionair are adjusted in parallel to give a turndown ratioof 3:1.The chain crate stoker can also achieve thisbut the sprinkler can be regulated much morequickly.
This type of stoker was popular initially because itwas very much cheaper than the chain grateequivalent. Its main drawback was that it had to be
de-ashed by hand. Effort has been put intodeveloping an automatic de-ashing system but,obviously, this has considerably eroded thesprinkler stoker’s price advantage.
Like the chain grate stoker, this type of stoker isselective with regard to fuel size. ‘Fines’ in the coalare picked up by the combustion air and flue gasesand carried through the boiler. This can causeconsiderable erosion within the boiler and resultin high grit emissions from the stack.
6.4 FLUIDISED BEDCOMBUSTION
Fluidised bed combustion is the most recent coal-burning technology, the fuel being fed onto a hot,air-agitated bed of refractory sand.This system hastwo main advantages:
1. It is much less selective in terms of fuel qualityand can burn not only very poor coal with ahigh ash content but even industrial orcommercial waste.
2. The lower combustion temperature involvedallows cheaper materials and refractories to beused in its construction.
However, this technology is still new and is in theexperimental stage in South Africa.
•
• • • • • • • • •
•
23
A short description of common equipment usedfor saving energy in boilers and furnaces follow. Insome cases these are discussed further under theenergy savings sections of either boilers orfurnaces.
7.1 FLUE GAS HEATEXCHANGERS
Since most of the heat losses from a fuel firedfurnace appear as heat in the flue gas, the recoveryof this heat can result in substantial energy savings.A common method is to install a heat exchangerat the furnace exit.
A heat exchanger can be used to transfer heatfrom the hot flue gas to the incoming combustionair, or to the heat water used elsewhere in theplant. The rate of heat transfer is proportional tothe surface area of the heat exchanger, and to themean temperature differential between the fluegas and the combustion air.
Q = U x A x LMTD x 3.6
Where, Q = Rate of heat transfer (kJ/h)U = Heat transfer coefficient of
heat exchanger [W/(m2·ºC)]
A = Surface area of heat ex-changer (m
2)
LMTD = Logarithmic mean tempe-rature difference (ºC)
3.6 = Conversion factor fromwatts to kilojoules per hour
LMTD = �T1 – �T2
LMTD =LMTD = �T1
LMTD = LnLMTD = (�T2 )
Where, LMTD = Log mean temperature dif-ference (ºC)
�T1 = Greater temperature differ-ence between the flue gasand the heated air or water(ºC)
�T2 = Lesser temperature differ-ence between the flue gasand the air or water (ºC)
“Ln” is the natural logarithm
A heat exchanger may be used to heat water withthe heat from flue gases. An important designconsideration is how close the heated watertemperature should be to the temperature of thehot gas entering the exchanger. It is not possible toheat the fluid to a temperature above thetemperature of the hot gas entering, regardless ofthe relative fluid and hot gas flows. Smalltemperature differentials imply large heatexchanger surfaces. This is illustrated by thefollowing example.
7. energy saving equipment
• • • • • • • • • • • • • •
•
24
Figure 8:Tempering Air Heat Exchanger. (Source: Canadian Gov.)(Energy Management Series 7. Page 18. Figure 11.)
Example of savings
A heat exchanger is to be added to a dryer which is exhausting 450 000 m3/h of moist air at 100ºC.The
exhausted air is used to heat up 350 000 m3/h of incoming air from an ambient temperature of 10ºC to
85ºC, which is within 15ºC of the hot exhausted air (Figure 8). The heat exchanger design has a heattransfer coefficient quoted by the manufacturer of 28 W/(m
2·ºC). Heat given up by the exhausted air is
equal to the heat gained by the incoming air, since there are no significant heat losses in a heat exchangerof this type. Density of air at standard conditions is 1.204 kg/m
3, and specific heat is 1.006 kJ/(kg·ºC).The
surface area of the heat exchanger required can be calculated as follows:
Cold air heat gain (Q) = Volumetric flow x Density x Specific heat x Temperature rise= 350 000 m
3/h x 1.204 kg/m
3x 1.006 kJ/(kg·ºC) x (85-10)ºC.
= 31.79 x 106kJ/h
Exhaust air heat loss = Volumetric flow x Density x Specific heat x Temperature drop= 450 000 x 1.204 x 1.006 x (100ºC – Tout) kJ/h
Cold air heat gain = Exhaust air heat loss
This can be expressed as:
31.79 x 106
= 450 000 x 1.204 x 1.006 x (100ºC – Tout) kJ/h
Rearranging the equation:(100ºC - Tout) = 31.79 x 10
6
(100ºC - Tout) =(100ºC - Tout) = 450 000 x 1.204 x 1.006
= 58.3ºC
25
Heat exchanger exhaust temperature,Tout = 100ºC – 58.3ºC = 41.7ºCMaximum temperature differential, �T1 = 41.7ºC – 10ºC
= 31.7ºCMinimum temperature differential, �T2 = 100ºC – 85ºC = 15ºC
The logarithmic temperature difference (LMTD) is:
LMTD = 31.7˚ C – 15˚ CLMTD =LMTD = 31.7˚ CLMTD = InLMTD = ( 15˚ C )
= 22.3ºC
Cold air heat gain (Q) = 31.79 x 106kJ/h = 28 W/(m
2·ºC) x A x 22.3ºC x 3.6 kJ/Wh
Surface area, A = 31.79 x 106
Surface area, A =Surface area, A = 28 x 22.3 x 3.6
= 14 142m2
If the cold air is heated to within 5ºC of the exhausted moist air instead of 15ºC, the size of the heatexchanger required in increased considerably.The calculations are as follows:
Temperature of heated air = 100ºC – 5ºC= 95ºC
Cold air heat gain = 350 000 m3/h x 1.204 kg.m
3x 1.006 kJ/(kg·ºC) x (95 – 10)ºC
= 36.03 X 106kJ/h
(100ºC – Tout) = 36.03 x 106
(100ºC – Tout) =(100ºC – Tout) = 450 000 x 1.204 x 1.006
= 66.1ºC
Tout = 100ºC – 66.1ºC= 33.9ºC
�T1 = 33.9ºC – 10ºC= 23.9ºC
�T2 = 100ºC – 95ºC= 5ºC
LMTD = 23.9˚ C – 5˚ CLMTD =LMTD = 23.9˚ CLMTD = InLMTD = ( 5˚ C )
= 12.1ºCSurface Area (A) = 36.03 x 10
6
Surface Area (A) =Surface Area (A) = 28 x 12.1 x 3.6
= 29 541 m2
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7.1.1 ECONOMISER (FEEDWATER
HEATER)
This is applicable mostly to boilers, and is anoption used for heating incoming boiler water bycooling the flue gases. The equipment is a gas-liquid heat exchanger. Care must be taken not toallow the flue gases to cool below the sulphurdew point. Economizers can be considered wherehot water is required. For furnaces, if the use ofhot water and the operation of the furnace do notalways occur simultaneously, it may be practical toinstall an insulated hot water storage tank. Thiswould level out the effect of variations in the hotwater supply and demand.
7.1.2 RECUPERATOR (AIR HEATER)
In a recuperator air entering the combustionchamber is preheated using the heat of the hotexhaust flue. This is an important measure forfurnaces where preheating the feed with flue gasesis more difficult that for boilers.The hot gas passesinside tubes arranged in bundles.The combustionair is directed over the outside of the tubes bymeans of a series of baffle plates. Combustion airpre-heat has always been regarded as the poorcousin of the economizer for boilers because airpre-heaters are large and less efficient than a gas-
liquid heat exchanger - or economizer - used toheat boiler feed water.
7.2 ACCUMULATORS
Boilers produce steam to meet demand. Whenspikes in this demand occur, or the load is uneven,it is often the case that an extra boiler would haveto be used intermittently, or output of severalboilers would rise to meet this demand. In the firstcase this can be inefficient due to losses associatedwith the heating and cooling of the boiler shell. Inboth cases, some of the required boiler capacity(and running and capital outlay) could have beenavoided by using an accumulator.
An accumulator effectively ‘stores’ or ‘accumulates’steam from boilers during times of low demandand then can release it during short high demandintervals.
7.3 INSULATION
Insulation is used to retain heat within the furnaceor boiler enclosure. Common insulation materialsinclude calcium silicate, mineral fibre, ceramic fibre,cements, cellular glass and glass fibre.An indicationof the heat loss from the hot walls of a furnace orboiler is given in figure 9.
It should be noted that the reduction in the temperature differential to 5ºC would require the heatexchanger area to be slightly more than doubled. An increase in design temperature rise of the incomingair from (85ºC – 10 0ºC) = 750C to (95ºC – 10ºC) = 85ºC results in an increase in heat recovery of
(85˚ C – 75˚ C)(85˚ C – 75˚ C) x 100 = 13%
75˚ C
A careful analysis of capital costs and savings in fuel costs for different possible heat exchanger sizes isimportant.
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27
A significant development in this field, for furnaces,has been the use of ceramic fibre insulation, whichis a better insulator than solid refractory materialand also requires less heat to reach the operatingtemperature. The disadvantages are higher initialcost and low resistance to physical damage.A layerof refractory on the bottom of the furnace andother areas subject to damage is normally used toprotect the ceramic fibre. Further layers ofceramic fibre insulation can be installed on theoutside of the refractory as required.
7.4 O2 ANALYSERS
Systems for checking the O2 or CO2 content of aboiler flue gas have been available for a long timebut, historically, none have been sufficiently reliableto be incorporated in an automatic controlstrategy. Portable or permanently installed O2 or
CO2 monitoring equipment used by a well trainedand intelligent boiler operator is still the bestmethod of limiting excess air and hence increasingefficiency.
The production of the ‘zirconium cell’ for O2
detection has made available a reliable measuringsystem, and this has resulted in the developmentof various systems, which automatically control theamount of excess air, thereby overcomingvariations in the fuel and air parameters. Usingthese oxygen detection feedback controllers,usually termed oxygen trim control, allows muchlower excess air levels to be achieved throughoutthe operating range.
The simplest systems use the feedback signal toadjust the combustion air damper via a secondary(‘tory’) linkage. The most sophisticated systemsfeed directly back to a microprocessor unit, whichsets the combustion air/fuel ratio.
Figure 9: Energy loss from furnace or boiler wall as a function of wall temperature.(Source: Canadian Gov.) (Energy Management Series 7. Page 23. Figure 12.)
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7.5 VARIABLE SPEED FANDRIVES
Popular in Europe and Japan are variable speeddrives for motors.They are used in this context, todrive combustion air fans. By varying their speed(together with electrical input) to match airrequired electrical energy can be saved duringperiods of partial load. Conventionally the airflowis limited via dampers, while the motor runs at afixed speed. At low loads this can lead to adisproportionately high electricity demand.Variable speed drives are economically lessattractive in South Africa due to relatively lowelectricity charges.
7.6 FLUE GAS DAMPERS
For situations where boilers or furnaces areregularly shut down because of changes in load,the heat loss caused by the chimney effectdrawing cold air through the boiler can besignificant.This is particularly true when a numberof units are connected to a common header andare operated in a cascade manner.
In the past the main problems encounteredincluded designing dampers that were virtually gastight, and incorporating a control system thatwould prevent the boiler firing against a closeddamper. Today, automatic gas-tight shut-offdampers for installation in a boiler exit flue arewidely available. In the case of forced draught (FD)oil and gas burners a cheaper alternative isavailable, particularly for retrofit situations: thisinvolves the installation of an automatic damper atthe combustion air fan inlet.
7.7 WASTE HEAT BOILERS
Waste heat boilers use hot flue gas to producesteam. In most instances there is a common steamheader into which the waste heat and fuel firedboilers are connected. The fuel fired boilers willthen supply the difference between the steamdemand and the steam supplied by the waste heatboiler.
Economizers are often used with waste boilers topreheat the feedwater to the boiler. The hot fluegas passes through the boiler before going to theeconomizer.
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•
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Sulphur compounds produced by combustion,escape into the atmosphere and have variouseffects. These include the production of acid rainand ambient pollution that is hazardous to humanhealth. It has also been postulated that otherproducts of combustion, such as CO2 are causingglobal problems, and this has led to an emphasison ‘Green’ policies in many countries.
Combustion products which are widely report tobe damaging to the atmospheric environment areparticulate emission, sulphur compounds (SOx),nitrogen oxides (NOX), carbon dioxide (CO2),methane (CH4) and nitrogen compounds (NOx).
Although a process for producing low sulphur fueloils has been in existence for many years, it isexpensive: it adds to the cost of a litre of oil andleaves sulphur residues which have to be disposedof without causing alternative forms of pollution.Limestone, when burned with coal will, however,trap 80% or more of the sulphur released by thefuel. The sulphur content of natural gas is verysmall and nearly all of that is deliberately added asthe stenching agent (so that the gas can bedetected).
There are basically two systems for removingsulphur from flue gases: the wet scrubbing methodwhich washes the SOx out using water : and thedry method of adsorbing the SOx onto limestonetype compounds. The wet process produces adirty acid that has to be disposed of withoutcausing pollution, and the dry method producesquite large volumes of spent absorber, which,again, must be disposed of safely.
CO2 is inevitably formed as a result of burning any
conventional fuel. Again, it could to some extentbe removed either by wet scrubbing or byabsorption.The current emphasis is on improvingoverall combustion efficiency so that less fuel isburned: this, in turn, reduces the production ofCO2.
Particulate emissions are considered to be themost ‘dangerous’ in the South African context.Ambient particulate levels are high and believedto be the most significant cause to poorrespiratory health among South Africans. Whilesome particulates are emitted into theatmosphere others are caught in pollution controlequipment or (especially with larger particles) inthe combustion equipment. This has to beresponsibly managed.
The production of NOx can be restricted bycorrect design of the combustion systems. Themost significant problem occurs with those fuelshaving the highest flame temperatures, i.e. fuel oiland gas. However in the case of coal a significantcontributor to nitrogen oxide formation is thenitrogen content of the fuel, which is generallyhigher than in oils and gas.A great deal of researchhas gone into developing low excess air burners,which have been shown to limit NOx production.
Plant manufacturers are being compelled toincorporate these new standards into theirdesigns. However, it is not enough for a boileroperator merely to have bought plant, whichmeets the new standards: he will have todemonstrate that it achieves those standards inday-to-day operation.
It is also recognized that ash and grit from coal-
8. POLLUTION
• • • • • • • • • • • • • •
30
fired equipment contain undesirable substancessuch as heavy metals etc. These also offer thepotential for environment pollution, and theirdisposal and dumping will similarly be subject togreater control in the future.
8.1 ENVIRONMENTALEQUIPMENT
8.1.1 ASH HANDLING EQUIPMENT
All solid fuels produce ash that must be removed.The ash is in ‘bottom ash’ and ‘fly ash’ forms.Bottom ash is from the coarse particles of slagthat fall into the ‘ash pit’ under the combustionchamber. Fly ash is the fine ash that is carried withthe flue gas and deposits in the hoppers beneaththe economizer air heater dust collector andprecipitator. The conveying of this ash can beachieved mechanically, or by mixing the ash withair or water and blowing or pumping the mixture.Electrical energy is expended on drives forconveyors pumps, compressors or blowers andcare should be taken in the operation andmaintenance to ensure that system energy isminimized.
8.1.2 AIR POLLUTION CONTROL
EQUIPMENT
These systems are designed to reduce fly ash(particulates), sulphur oxide and nitrous oxideemissions from the boiler plant.This equipment isnot usually required on small boilers firing naturalgas or oil.
• Mechanical cyclone collectors (dust collec-tors) remove particulates by centrifugaland gravitation forces developed in a
vortex separator.Their use is now limitedto small stoker-fired units because of theirlow collection efficiency of very smallparticles.
• Electrostatic filters precipitators electricallycharge suspended particles in the gas andthen attract them to collecting plates withan electric field. The collecting plates arethen trapped to cause the particles todrop into hoppers. Precipitators can bedesigned for a high collecting efficiency of98 per cent or more.
• Fabric filters, or baghouses, have a longhistory of applications in dry and wetfiltration processes to recover chemicalsor control stack emissions.The dirty gas ispassed through fabric filters with theparticulate matter forming a cake on thefabric.The deposit is periodically removedfrom the filter by mechanically shaking thefabric, or by a pulse of air. Fabric filters canbe designed for collecting 99 per cent ofparticulates or more.
• Lime or limestone scrubbing is the oldestmethod of removing sulphur dioxide fromflue gas. The boiler flue gas enters aVenturi scrubber and contacts theinjected absorbent lime slurry.The flue gasthen passes through a vertical spraytower where the slurry and absorbedsulphur compounds are washed out ofthe gas.
All items of pollution control equipment usevarying amounts of electrical energy thatsignificantly increase the energy used per plantoutput. It is imperative that operation andmaintenance staff keep this equipment in first-rateworking order.
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The boilers considered in this guide are limited tothose that produce either steam or hot waterfrom the combustion of a fuel. While electrodeboilers are used for generating steam fromelectricity, they are not considered here. Themajority of energy savings measures describedbelow are limited only to combustion processesand are not applicable to electrode boilers. Theexceptions to this include issues relating to blow-down and insulation. These concepts may beapplied to saving energy in electrode boilers withminor adjustments.
9.1. TYPES OF BOILERS
There are various types of boilers that havedifferent configurations and run on various fuels.The configurations are described below.
If operated correctly, all types of modern boilerare more or less equally efficient at converting fuelinto steam or hot water. Table 1 indicates theexpected thermal efficiencies obtainable fordifferent boiler types, based on the gross calorificvalue of the fuel.
Although different types of boiler appear to varyconsiderably in their construction, all boilersconsist basically of a furnace chamber in whichheat is transferred directly from the flame byradiation, and flue gas passages where the heat isprimarily transferred by convection to water beingheated. Two-thirds of the heat transfer to thewater takes place in the furnace and the remainingthird in the flue gas passages. Heat not transferredis lost in various forms.
There are two fundamental types of boiler : thewater tube type where the water is contained inpipes and the hot combustion gases pass aroundthem; and the shell or fire tube type where theopposite is true.All other boilers are derivatives ofthese two types and have been designed to meeteither differing size or dimensional limitations, ordiffering operational requirements.
The boilers described below include:
• water tube boilers,• multi-tubular shell boilers,• reverse flame or thimble boilers,• steam generators,• sectional boilers,
9. BOILERS
• • • • • • • • • • • • • •
•
Table 6: Boiler Efficiency According to Boiler Type
Boiler Type Efficiency %Condensing Gas 88-92High Efficiency Modular 80-82Shell Boiler – Hot Water 78-80Shell Boiler – Steam 75-77Reverse Flame 72-75Cast Iron Sectional 68-71Steam Generator 75-78Water Tube with Economiser 75-78
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• condensing boilers,• modular boilers and • composite boilers.
9.1.1 WATER TUBE BOILERS
Water tube boilers tend nowadays to beconsidered only for large steam outputs, whichoften require superheated steam. For mostindustrial and commercial applications, however, amulti-tubular shell boiler is more appropriate. Onlyif the requirement is for an industrial output above20 MW and/or at pressures above 24 bar orsteam temperatures above 340ºC is it necessaryto use a water tube boiler.
The reason for this is that water tube boilers costmore to build for a given steam output than domulti-tubular shell boilers. The shell boiler can beentirely factory fabricated, mounted on a skid withall its associated equipment (such as feedwaterpump. burner. and control panel), and thendelivered direct to site. The output and pressurelimits for the shell boiler are, however, determinedby the feasibility of transporting the completedunit from the fabrication plant to the site.
The output from water tube units starts at about8.5 MW and rises to power-station-sized unitsrated at 2000 MW and above. At the bottom ofthe range, units can be manufactured anddelivered to the site in one piece.The larger unitsare manufactured in sections and delivered for siteerection. A typical schematic of an industrial watertube boiler is shown in Figure 10.
9.9.1.1 PACKAGED WATER TUBE
BOILERS
Natural gas or oil fired units are usually deliveredas factory assembled “packaged” boilers. Packagedboilers range in size from about 1500 to l90 000
MJ/h, which covers the normal size range of mostboilers. For solid fuels, the boilers are site erected,as the large size of the combustion chamber andfuel-firing equipment does not make shipmentpossible.
The water to be heated is carried inside banks ofsteel tubes, with the hot gas on the outside of thetubes. The most common boilers consist of adrum connected by vertical tubes (downcomers)to a lower drum or header(s). The downcomerscan be heated or unheated. A further set of tubes(risers) connects the two drums and forms thewalls of the combustion chamber (Figure 10).Natural circulation begins when the heat suppliedto the risers exceeds that supplied to thedowncomers, thereby producing a mix of steamand water in the risers of less density than that ofthe water in the downcomers.
The traditional water tube boiler relies on watercirculation occurring as a result of the thermal-siphon effect: the hot water to the boiler is lighterand rises, drawing in colder water at the bottomto replace it. A variation that allows for a morecompact design using smaller diameter tubes is theforced circulation boiler, where the feedwater ispumped through the water tubes.
Hot water boilers are similar in appearance andoperation to steam units.The circulation of waterthrough the tubes is achieved by pumping.
Water tube boilers are not often used for hotwater production. If they are used for thispurpose, it is usually as a ‘Lamont’ boiler.The majorpotential problem with this type of boiler occurswhenever a power failure stops the circulationpumps, especially in the case of coal fired plant,steam is generated within the tubes and this canlead to overheating of the metal, softening andsubsequent tube failure unless the fire can rapidlybe drawn and cooling air can be provided at theconvective tube bank. This type of plant cannottherefore be used in a fully automated, unmannedboiler house.
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Figure 10:Water Tube Boiler with Natural Convection. (Source: ETSU)(Good Practice Guide 30. Page 49. Figure 28.)
Figure 11: Forced Water Circulation Water Tube Boiler. (Source: ETSU)(Good Practice Guide 30. Page 50. Figure 29.)
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One of the main advantages of the water tubeboiler in the 10-20 MW range, where it is in directcompetition with the shell boiler, is its ability toreact rapidly to load changes.The water tube unitcontains only a fraction of the water in a shellboiler so the thermal inertia of the system is muchsmaller.
Water tube boilers can be tired using anyindividual conventional fuel or they can operate asmulti-fuel units.
All watertube boilers are capable of operatingcontinuously at any load, from about 15 to 100per cent of the rated capacity.The highest thermalefficiency normally occurs at about 85 per cent ofrated capacity, with efficiencies falling moresignificantly at loads lower than 60 per cent. Thesmall internal water capacity permits quickresponse to sudden steam demand changes, andfrequent start-up and shutdown operation.
The best energy utilization of a watertube boilerresults from steady demand at 85 per cent ofrated capacity with the avoidance of suddenswings in demand or frequent shutdowns.
9.1.2 MULTI-TUBULAR SHELL
BOILERS
These are essentially shell and tube heatexchangers where the combustion gas passesthrough tubes immersed in water. Firetube boilersusually burn natural gas or oil, although some, witha firebox type of combustion chamber, can beinstalled on top of a coal or wood burning stoker.They can generate dry saturated steam or hotwater up to a maximum pressure of 1700 kPa(gage). The output ranges from 350 to 28 000MJ/h. The boilers are shop assembled anddelivered with integral burner, forced draft fan, andcontrols.
As materials and manufacturing processesimproved, thinner metal came to be used for thetubes allowing more tubes to be accommodated.At this stage in its development the basic boilerwas rather long and thin and required a largeboiler house area. By making the hot gases gobackwards and forwards through a series of tubes,the boilers were designed to be shorter and fatter,and heat transfer rates were improved. Themodern multi-tubular packaged boiler is the logicalconclusion to this evolutionary process. Thepackaged boiler is so called because it comes as acomplete package. Once delivered to site itrequires only the steam, water pipework, fuelsupply and electrical connections to be made forit to become operational.
These boilers are classified by the number ofpasses - the number of times the hot combustiongases pass through the boiler. The combustionchamber is taken as the first pass after which theremay be one two or three sets of fire-tubes. Themost common boiler is, a three-pass unit as shownin Figure 12 with two sets of fire-tubes and theexhaust gases exiting through the rear of theboiler. Older two-pass units transfer heat lessefficiently, fewer fire-tubes giving a smaller heattransfer and the flue gases still containingconsiderable heat when they leave the boiler.Many such units have had equipment fitted torecover some of this potentially lost heat into theboiler feedwater.
Four-pass units are potentially the most thermallyefficient but fuel type and operating conditionsmay prevent their use. When this type of unit isfired with heavy fuel oil or coal at reduced output,the heat transfer can be too good. As a result theexit flue gas temperature can fall too low causingcorrosion of the flues and chimney and possibly ofthe boiler itself. The four-pass boiler unit is alsosubject to high thermal stresses especially if largeload swings occur suddenly: these can lead tostress cracks or failures within the boiler structure.
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Another classification is related to the chamber atthe end of the combustion chamber before thehot gases enter the fire-tubes. If this chamber isentirely contained within the water shell it isclassified as a ‘wet-back’ boiler, and if the chamberis refractory mounted on the outer plating of theboiler the boiler is classified as a ‘dry-back’ unit.Thewetback configuration reduces the number of fire-tubes and hence, marginally, the boiler size byincreasing the heat transfer area at the pointwhere the flue gases are hottest. Multi-tubularshell boilers are available which will fire any of theconventional fuels or any form of industrial orcommercial waste.
The original convention was to produce two typesof shell boiler : one with a small combustionchamber and many fire-tubes for firing gaseous orliquid fuels: and one with a larger diametercombustion chamber and fewer fire-tubes forfiring solid fuels. The design variation resulted notonly from the need for more space to incorporate
a coal stoking system but also from the verydifferent flame temperatures and combustioncharacteristics of the various fuels. Older unitswere also separately designed for gas and oil firing,again because of the combustion characteristics ofthe two fuels. Many of the older oil-fired units hadto be de-rated when converted to gas firing:without this de-rating the temperature of the fluegases entering the first pass of tire-tubes wasfound to be too high, causing additional thermalstress and leading to early boiler failure. Some ofthe modern units, however, are manufactured withan intermediate size of furnace tube and arecapable of firing all three fuels.
Recent design trends have been towardsincorporating many more fire tubes of a smallerdiameter in the boilers to make them morecompact. However, one of the major advantagesof the older types of shell boiler is their very largewater content which provides a large potentialsteam reservoir during periods of rapidly
Figure 12: Schematic of multi-tubular three-pass boiler. (Source: ETSU)(Good Practice Guide 30. Page 51. figure 30.)
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increasing load. The large water surface area alsoresults in drier steam. Modern designs eliminatethis advantage, making shell boilers behave morelike water tube units, but at the same time thelower water content of the modern boilers meansthat they can generally be heated through andbrought on-line more quickly.
Boilers rated up in 12 MW are usually supplied witha single burner or stoker and those between 12 and20 MW with two burners or stokers, each in aseparate furnace chamber. In some of these twinfurnace units the flue gases from each chamber arekept separate until they meet at the boiler exit.Theadvantage of this is that it is possible to operate theplant with only one burner firing, giving a muchlower minimum output from the boiler. If the flue gaspassages are combined, single burner firing mayresult in the flue gas temperature falling too low,thereby causing corrosion.
Multi-tubular shell boilers dominate the market foroutputs between 3 and 20 MW. Even below 3MW, derivatives of this basic design predominate.
9.1.3 REVERSE FLAME OR THIMBLE
BOILERS
As indicated above, the major problem with multi-tubular shell boilers is thermal stress broughtabout by differential expansion. The expansion ofthe furnace tube is much higher than for the firstpass of smoke tubes - and this, again, is higher thanfor the second pass. This puts stress on the tubeplates supporting each end of the boiler.
The reverse flame or thimble boiler is an attemptto reduce the problem by using a ‘floating’combustion chamber. As shown in Figure 13 the
Figure 13: Schematic of reverse flame boiler. (Source: ETSU)(Good Practice Guide 30. Page 52. Figure 31.)
37
combustion chamber is only attached to the fronttube plate.
These boilers are still classified as three-pass unitsbut two passes occur within the combustionchamber as the flame reverses and only one passinvolves convective fire-tubes. In practice theadditional heat transfer from the second passthrough the combustion chamber is relatively lowmaking this design little better than a two-passconventional shell boiler
The other main advantage of the reversing flameis that it reduces the length of combustionchamber required making the boiler morecompact. Space is often a problem when hotwater or steam boilers are installed within existingboiler-houses or buildings, so the relatively smallfloor area required by a thimble boiler can be anadvantage.
As there are relatively few short fire-tubes in thefinal pass, heat transfer rates are low resulting inhigh flue gas exit temperatures. Heat transfer canbe improved by increasing the turbulence withinthe flue gases, and many manufacturers fit metalspirals or ‘turbulators’ within the tubes to improveefficiency.
Units of this type are currently manufactured forboth steam and hot water production and areavailable in the 150 kW – 3 500 kW range. Theflame-shape requirement means that only fuel oilor gases can be used, and most boilers of this typeoperate most efficiently when fired by fuel oil.
9.1.4 STEAM GENERATORS
Steam generators are derived from the watertube type of boiler. In practice they are smallforced-circulation water tube boilers. Asmanufactured they are very compact, lightweightand capable of producing steam very rapidly from
a cold start-up. They therefore react very quicklyto load fluctuations.
Unlike the conventional water tube boiler there isno steam/water separation header drum (Figure14). The water, as it is pumped through thecombustion chamber, partially flashes into steam,and then passes through a steam separator so thatdry process steam is available.The water from theseparators is then returned to the feedwater forrecirculation.
Heat transfer rates can be improved by reducingthe stagnant layers of gases and water that adhereto both sides of a heat transfer surface: stirring orincreasing the turbulence can achieve this.Fundamental to the design of a steam generator isthe maintenance of a high level of turbulence inboth the water and the flue gases: this ensureshigh heat release rates and good thermalefficiency.
Its small physical size, lightweight construction andrapid steaming potential make this type of boilerespecially suitable for decentralised steamdistribution systems. It does, however, have twodisadvantages: because of its very high evaporationrate good feedwater quality is essential, usuallynecessitating the use of demineralised water ;secondly, the steam generator does not cope wellwith high impulse steam loads.
Where a high peak demand occurs for a relativelyshort period it is better practice to fit a smallersteam generator together with a steamaccumulator, which gives a reserve of steam similarto that, provided by a conventional shell boiler
Steam generators are manufactured to provideoutputs ranging from 75 kW to 2.5 MW (a fewhundred to 3,000kg/hr). Their major advantage isthat they occupy very little space, even whenallowance is made for water treatmentequipment. They can therefore be sited almostanywhere within a factory.This means that if new
38
equipment is installed requiring steam at, say, 10bar, and if the existing distribution system is at 7bar, a single generator dedicated to that newequipment could readily be installed. Thealternative is to increase the existing distributionpressure, which may not be possible from anengineering point of view: even if it is feasible, heatand leakage losses will significantly increase.
9.1.5 SECTIONAL BOILERS
Cast iron sectional boilers are an oddity in thatthey do not obviously fall into one of the twofundamental boiler categories described above. Inprinciple, however, they more closely resemble ashell boiler.
For many years cast iron sectional boilersdominated the low output end of the market for
the generation of low and medium temperaturehot water (LTHW and MTHW). Within the 10-30kW output range only small steel and steelsectional boilers provide any competition. Athigher output levels there is competition first frommodular and condensing boilers (subsequentlydescribed) and then from the thimble boiler up toabout 750 kW.
The major advantage of the cast iron sectional unit isthat it is much more resistant to corrosion than anequivalent steel boiler when flue gas temperatures falltoo far. When firing natural gas or LPG thisconsideration is trivial, but it is of much greatersignificance when firing fuel oil or coal. Anotheradvantage is that the method and the robustness of itsconstruction reduces the effect of thermal stressmaking it ideal for small space-heating applicationswhere the burner will fire ‘on’ and ‘off ’ quite frequently.
Figure 14:A steam generator. (Source: ETSU)(Good Practice Guide 30. Page 54. Figure 32.)
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To some extent the cast iron boiler’s pre-eminence is being challenged by stainless steelwelded boilers which are more compact, muchlighter in weight and more energy efficient.However, the former unit still offers a cheap andvery tolerant package suited to LTHWapplications.
9.1.6 CONDENSING BOILERS
The problem of corrosion caused by condensingflue gases has plagued boiler designers for manyyears. Hot flue gases may be wasteful from anenergy point of view but their natural buoyancy ina chimney means that combustion air is drawninto the boiler and flue gases can be removedwithout using electrical energy to drive fans. Untilrecently, therefore, boilers were designed tomaintain flue gas temperatures at a sufficiently high
level to avoid condensation and corrosion. ForLTHW applications, with water temperatures of80ºC and below, this has always proved impossiblein practical terms and, as indicated in the previoussection, the solution has been the widespread useof cast iron sectional boilers.
The cooled combustion products of natural gasare only very slightly corrosive compared with oilor coal.This means that all the heat - both sensibleheat and the latent heat of the water vapourproduced during combustion - can safely berecovered, and condensing boilers have thereforebecome a practical alternative. These basicallyinvolve the incorporation of a heat exchanger inthe exhaust flue as shown in Figure 15.
Because some corrosion will still occur, the originaldesigns used two different materials for the heatexchangers: cast iron and stainless steel. Stainless
Figure 15: Condensing boilers. (Source: ETSU)(Good Practice Guide 30. Page 56. Figure 33.)
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steel heat exchangers are now more widely usedbecause they are very much more compact andso can be fitted to boilers as small as 30kW. Unitsare now manufactured up to 600 kW and theprinciple can still be applied to larger units: in thelatter case, the heat exchanger is referred to as acondensing economiser.
In general, these units are fired using natural gas orLPG. As it is the sulphur content of the fuel that isresponsible for the corrosion, any low sulphur or‘clean’ fuel can be used.The alternative is to cleanthe flue gases before the flue vapour is condensed,so for larger boilers a condensing economisermight be installed after a flue gas desulphurisationprocess.
The energy from the heat exchanger is used topre-heat the feedwater going to the boiler. Thelower the feedwater temperature, the more heatis recovered by the heat exchanger therebyincreasing the efficiency of the complete boilerpackage. Figure 16 shows that efficiencyimprovements of up to 10% are achievable.
9.1.7 MODULAR BOILERS
Where the demand for heat varies on an hourly,daily and monthly basis, as with space heating forlarge commercial premises, the installation of asingle large boiler is not very efficient. A boiler ismost efficient when operating continuously atabout 85% of its rated output so. Under thesecircumstances, it is more energy efficient to installseveral smaller boilers and to operate only thenumber necessary to meet the heat demand.
The logical outcome of this reasoning is theinstallation of ‘modular boilers’ consisting of anumber of identical small units controlled incascade fashion. The earliest systems usedconventional cast iron sectional or small steel shellboilers and, for larger installations, this hasremained the case. However, high-efficiency heatexchange units have been specifically designed forthe lower end of the output range.
The advantage of modular systems is that the
Figure 16: Condensing boiler efficiency graph. (Source: ETSU)(Good Practice Guide 30. Page 57. Figure 34.)
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many turndown stages allow individual units tooperate close to their maximum efficiency at alltimes. In a well designed system no watercirculates through the boiler when it is off, and thisreduces the potential heat loss. Figure 17 showsthe type of pipework and valve layout that wouldtypically be installed. Such systems are under fullyautomatic control and are either oil or gas fired.
There is no upper limit to the maximum outputfrom a modular boiler set because, if more heat isrequired, another boiler or heat exchanger unitcan be added. The basic building blocks of thesystem start at about 10kW but units of 100kWor more could equally be used. A full financialassessment would be required to define the idealmodular boiler set for a particular potentialinstallation.
9.1.8 COMPOSITE BOILERS
A composite boiler is not, as its name implies, a
cross between a shell boiler and a water tubeboiler. This type of boiler is used to burn twodifferent fuels - often a waste product or wasteheat and a conventional hydrocarbon fuel. Thewaste or solid fuel is fired in one combustionchamber and the hot combustion gases pass to asecond combustion chamber where theconventional fuel is fired to make sure that totalcombustion has been achieved. Depending on thedesign, the hot gases from the first chamber maypass over part of the boiler heat transfer surfacesbefore entering the second chamber. Alternatively,the gases may only pass through the boiler aftercombustion has been completed.
It is becoming increasingly popular to takeadvantage of the energy stored in variousindustrial and commercial wastes rather than to
incur the often considerable expense of disposal.Originally, use was made of conventionalincinerators attached to waste heat boilers, butthe efficiency of heat recovery was usually low.The
Figure 17: Schematic of Modular Boiler System. (Source: ETSU)(Good Practice Guide 30. Page 58. Figure 35.)
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composite boiler is one outcome of an ongoingdesign and development programme for wasteburning boilers, which has been undertaken bymanufacturers.
9.2 BOILER SYSTEMSELECTION
This Guide has examined the various problemsassociated with boilers, fuels and pollution. If allthese factors are taken into consideration, boilersystem selection becomes more difficult, andadditional guidelines are required.
The first decision involves the selection of a steamor hot water system: the appropriate choice isusually very clear.The next step is to evaluate theoverall size of the system and how the load is likelyto fluctuate. A large steady load ideally requireslarge boilers, but a load, which fluctuates on an
hourly, a daily or a seasonal basis, will be met moreefficiently if several smaller boilers are installed.
The third step is to identify the appropriate boilersfor the job. The flowchart in figure 18 offersguidelines for the selection of steam boilers basedon the output and conditions required. Generally,for each output level several boiler choices areavailable.
Small boilers are fuelled only by gas or oil, so thecosting is fairly simple. All fuel options, however,are open in the case of the larger boilers so moreinformation on capital, operating and maintenancecosts must be obtained either from equipmentmanufacturers or, possibly, from existing plantusers. In all cases, when the selection of new orreplacement boiler plant is undertakenconsideration should be given to the installation ofCombined Heat and Power (CRP) schemes.
•
Figure 18: Boiler selection flow chart for steam boilers. (Source ETSU)(Good Practice Guide 30. Page 74. Figure 41.)
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10.1 POTENTIAL LOSSES4
To optimise the operation of boiler plant it isnecessary to understand where energy wastage islikely to occur. Figure 19 shows all the inputs andoutputs for a typical oil or gas-fired boiler. Withcoal-fired plant there would be additional losses inthe heat and combustible content of the ash. Foran oil-fired steam boiler with the characteristicslisted below an overall thermal efficiency of 75% isnormal under typical operating and maintenanceprocedures.
Boiler rating 2.7 MWSteam Pressure 7 bar gFeed Water Temperature 50ºCFlue Gas Temperature 232ºC
10.2 BOILER ENERGYBALANCE
The three sources of boiler heat energy input arethe fuel, feedwater and combustion air.The majorenergy source is from the fuel, which can beexpressed in terms of MJ/m
3for gas and MJ/L for
oil. In the case of some oils it is necessary to heatthe oil in the storage tank sufficiently to permitpumping and then heat it further prior to going tothe burner. The thermal energy of the oil as it isdelivered to the boiler should be added to thehigher heating value of the oil to represent the totalfuel energy input.
The feedwater temperature must also be
10. energy and cost saving forboilers
• • • • • • • • •
Figure 19: Boiler inputs and losses. (Source ETSU)(Good Practice Guide 30. Page 77. Figure 43.)
••
4A comprehensive boiler heat balance is given in the appendix. This gives both the direct and indirect method for evaluating efficiency, and a
breakdown of the losses.
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considered as part of the energy input (i.e. highertemperature feed-water requires less heat energyfrom the fuel to be converted to steam). Thefeedwater temperature can be used to determinethis heat energy input level.The energy content ofthe feedwater is the enthalpy (hf) as determinedin steam tables corresponding to the feedwatertemperature.
Combustion air is normally drawn from within theboiler plant, but it may be ducted from outsideand heated with steam. A higher combustion airtemperature will reduce the energy input requiredfrom the fuel.
10.3 MINIMIZING BOILERLOSSES
Energy loss is a crucial topic in terms of efficientboiler plant operation. The losses that followcan be influenced by design and operatingfactors.
The major controllable heat losses and hencethe target areas for improvement are detailedbelow.
10.3.1 MAINTENANCE SAVING
OPPORTUNITIES
Some significant energy savings can be made bycareful maintenance, specific examples are givenbelow:
1. Maintain proper burner adjustments. It is a goodidea to have an experienced burnermanufacturer’s representative adjust theburners. The operator can then identify theappearance of a proper burner flame for futurereference. The flame should be checkedfrequently, and always after any significantchange in operating conditions.
2. Overhaul regenerative air heater seals. Excessiveamounts of air can leak from the air side to thegas side of the air heater if the seals are in poorcondition.This results in increased forced draftfan power consumption and may reduce themaximum boiler capacity.
3. Check boiler easing for hot spots.“Hot spots” arean indication of excessive heat losses from theboiler enclosure. The temperature of thesurface of the outer skin should not be morethan 50ºC, although higher temperatures may
Figure 20: Boiler Energy Balance. (Source: ETSU)(Good Practice Guide 30. Page 77. Figure 43.)
•
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be unavoidable where insulation cannot beinstalled, such as around the burner assembly.Eliminating hot spots is a safety measure, andwill help to maintain comfortable workingconditions.
4. Replace or repair missing and damagedinsulation. Substantial quantities of heat are lostfrom bare steam and hot water lines.
5. Replace boiler doors and repair leaking doorseals. Leakage of air or gas will create the sameproblems as described in Example 4. Inaddition, an open furnace door will causeconsiderable heat loss by radiation of heatfrom the furnace to the outside.There is also adanger that a furnace upset will cause hot gasto be ejected suddenly through the opening tocreate a personnel safety hazard.
6. Repair malfunctioning steam traps. Steam trapsmay fail in the open or the shut position. Anopen steam trap will pass excessive quantitiesof steam to increase the heat loss. A closedtrap will not permit condensate to escape. Ifthe trap is connected to a heat exchanger, theheat exchanger will gradually fill withcondensate and eventually fail to operate. If theheat exchanger is heating outside air, thecondensate may freeze in winter and damagethe tubes of the unit. If the closed trap isdraining a steam line, excessive condensatemay build up in the line to cause waterhammer in the system.This may damage fittingsand equipment. A regular steam trapmaintenance program is a very positive steptoward minimizing energy losses.
7. Calibrate and tune measurement and controlequipment. A common cause of deterioratingboiler efficiency is operation at higher excessair values than necessary. If the combustioncontrol system is not operating properly there
is a tendency to increase the air flow to ensurethat the fuel-air ratio will not becomeexcessive for load changes or upset conditions.If the fuel-air ratio is too high, meaning thatthere is a deficiency of combustion air, there isa possibility of unstable combustion conditions,which could lead to a furnace “puff ”. Aproperly operating combustion control systemwill permit operation at the lowest attainableexcess air level while maintaining propercombustion during load changes. Typically areduction in the excess air from 20 to 10 percent will increase the efficiency 1.5 per cent.
10.3.2 BLOWDOWN HEAT LOSS
This loss varies between 1% and 6% and dependson a number of factors:
• total dissolved solids (TDS) allowable in theboiler water :
• the quality of the make-up water, whichdepends mainly on the type of water treatmentinstalled (e.g. base exchange softener ordemineralisation):
• the amount of uncontaminated condensatereturned to the boilerhouse:
• boiler load variations.
Correct checking and maintenance of feedwaterand boiler water quality, maximising condensatereturn and smoothing load swings will minimisethe loss. The installation of blowdown heatrecovery systems will help to control the loss.
EXAMPLE
Diverting the flash steam to the de-aerator and/or putting the blowdown water through heat exchangersto heat the feedwater make-up can recover blowdown heat.
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10.3.3 HEAT TRANSFER
In modern shell and water tube boilers some 70%of the total heat transfer takes place in thecombustion chamber by radiation. The threefactors influencing radiant heat transfer are:
1. Flame temperature:
2. Flame shape:
3. Fouling of heat transfer surfaces.
In principle a bright clear flame or fire bed, whichfills the combustion chamber withoutimpingement, satisfies all the criteria forsatisfactory heat transfer.
10.3.3.1 RADIATION HEAT LOSS
The radiation heat loss of a boiler is primarily afunction of the applied thermal insulation.Insulation reduces the heat radiating from theboiler and maintains the outside surfaces at atemperature low enough for safety. The surfacetemperature normally determines the quality andthickness of the insulation on the various sectionsof the boiler. Most safety regulations require thatmetal surfaces within reach of personnel notexceed 500C. The heat loss from the casing isdifficult to measure accurately. Figure 21 is derivedfrom the American Boilermakers’ AssociationStandard Radiation Chart, and can be used toestimate the heat loss. Radiation loss isindependent of the type of fuel fired, and use ofthis chart requires only knowledge of the outputrating of the boiler and the nature of the furnacewalls.
Consider a boiler evaporating 13 500 kg/h of dry saturated steam at 1400 kPa (absolute) with a blow-down rate of 5 per cent.The feedwater is supplied to the boiler at 1500 kPa and l05ºC.
Enthalpy of boiler water at 1400 kPa (absolute) 830.1 kJ/kg
Blowdown heat = 13 500 x 0.05 x 830.1 (above 0ºC)= 560 317 kJ/h
A study of the steam and feedwater systems shows that 75 per cent of the blowdown heat is recoverable.The boiler operates 5000 hours per year and fuel costs R50/GJ.Annual savings = 560317 x 0.75 x 5000 x 50Annual savings =Annual savings = 1 x 10
6
= R10 506
Blowdown heat recovery equipment including a heat exchanger to transfer heat from the blowdownwater to treated water make-up, plus the associated piping, costs in total about R150, 000.Simple payback = R150000Simple payback =Simple payback = R105060
= 1.4 years
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Figure 21: Radiation Loss from Boiler. (Source: Canadian Gov.)(Energy Mangement Series 6. Page 13. Figure 12.)
Example 1
For example, consider a packaged watertube boiler with a full load rated output equivalent to 50 GJ/hwith all four furnace walls water cooled. From the chart, the heat loss due to radiation would be 0.65 percent of gross heat input. Note that if the boiler were operating at half capacity, the radiation loss would be14 per cent of gross heat input. It can therefore be seen that a penalty will be paid, in increased percentageradiation losses if a boiler is operated on part load for an extended period of time.The absolute heat lossto the flue gas would be lower at part load, because the gas volume is lower. However, the overall boilerefficiency would likely be lower.
The remaining 30% of heat transfer is by convection from the hot flue gases and this is determined mainlyby the flue gas velocity and degree of surface fouling.The fouling of heat transfer surfaces is a result of sootand ash on the fire side and incorrect water treatment on the water side. In order to minimise thethickness of the boundary layer limiting heat transfer rates modern shell boilers use smaller multiple tubesand in some cases, induce additional turbulence to increase combustion gas velocity.
Example 2
Add insulation to areas previously left uninsulated or increase thickness in areas already insulated: Boilersinstalled 15 to 20 years ago were sometimes insulated for reasons of personnel protection rather thanenergy conservation. Insulation thickness was selected to give an outside casing temperature of 55ºC. Ifadditional insulation was added to reduce the skin temperature to 40ºC, the energy saving could amountto at least 0.25 per cent of the annual fuel bill. Also, some areas out of the reach of operating staff maynot be insulated.
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10.3.4 EXCESS AIR REDUCTION
10.3.4.1 THE SIGNIFICANCE OF
EXCESS AIR
For every fuel it is possible to calculate the exactamount of air that is needed for combustion. Inpractice, some surplus air is required to ensurecomplete combustion, the amount varying withthe type of fuel being burned. Any further excessair is heated, passes through the boiler and ispassed out of the stack, thereby reducing systemefficiency.
The effect on boiler efficiency of reducing excessair is shown in Figure 22.
When setting up a combustion system the aim isto use the minimum amount of excess air, whichwill ensure clean safe combustion. This minimumwill depend both on the type of fuel and on thetype of burner/stoker employed. Table 7 givesguidelines for good practice concerning thequantities of excess air required for four differentfuels. Newer equipment should be able to achievethe lower values in the range, but some olderequipment will have difficulty achieving even thehigher values.
Figure 22: Increase in boiler efficiency per 1% reduction in excess air versus stack temperature.(Source: ETSU) (Good Practice Guide 30. Page 78. Figure 45.)
Table 7: Recommended Excess Air Levels for Boilers
Fuel Excess Air (%) O2 in Flue Glass (%)Min Max Min Max
Natural Gas 10.0 15.0 2.0 2.7
Fuel Oil:
Light 12.5 20.0 2.3 3.5
Heavy 20.0 25.0 3.3 4.2
Coal 30.0 50.0 4.9 7.0
NB the above settings are typical for boilers without low excess air combustion equipment.
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Simply adjusting the excess air is not necessarilysufficient: the air must mix with the fuel at thecorrect point. Almost all combustion systems usetwo sources of combustion air : the air whichimmediately mixes with the fuel to initiatecombustion (the primary air): and that used tocomplete the combustion (the secondary air). It isessential that these are available in their correctratio to obtain complete, clean combustion.
Unless there is a system for regularly checking theflue gas constituents, greater excess air has to beused to allow for variations in the operatingparameters.These might include:
• changes in fuel composition - especiallyfor coal and heavy fuel oil;
• changes in the density of air betweensummer and winter, wet to dry etc;
• wear and tear, standard of maintenance,and the age of the combustionequipment.
10.3.4.2 AUTOMATIC CONTROLS
Automatic controls may be added to a boilersystem to ensure correct air ratios. In this case anumber of factors, such as the boiler firing rate,can be incorporated within the system.The initialsetting up of this type of computer-based systemrequires the O2 at a number of firing rates to beinput, usually in the form of a straight line. Manysystems incorporate a self-learning capability,which will modify the initial program, tailoring itexactly to the characteristics of an individual boilerburner/stoker configuration.
10.3.5 FLUE GAS HEAT RECOVERY
Most of the heat losses in a boiler are in the fluegas.The flue gas temperature should be as low aspossible above the dew point of sulphur gases,which could condense into acids, attacking thestack and associated equipment.
EXAMPLE
A boiler burning natural gas is operating at 60% excess air. Boiler efficiency has been tested and found tobe 77%. Annual fuel costs are R4 000 000. Recalibration of the controls and minor repairs to the burnerwindbox dampers cost R20 000.These changes permit operation at 40% excess air.
A reduction in excess air from 60% to 40% results in a reduction in flue gas losses from 21% to 19% at aflue gas temperature of 210ºC. Assuming that other losses and the flue gas temperature remainunchanged, the boiler efficiency will be 79%.
Annual fuel cost at 40% excess air = R4 000 000 x 77 = R3 898 730Annual fuel cost at 40% excess air = R4 000 000 x = R3 898 730Annual fuel cost at 40% excess air = R4 000 000 x 79 = R3 898 730Annual savings = R4 000 000 - R3 898 730
= R101 270Payback = R20000 = 0.2 year (2.4 months)Payback = = 0.2 year (2.4 months)Payback = R101270 = 0.2 year (2.4 months)
By ensuring that the flame is of a clear bright colour and nearly fills the combustion chamber, and thatexcess air is kept to a minimum, an increase in overall thermal efficiency of some 5% can be achieved.
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Figure 23 shows the typical corrosion curve for afuel oil and indicates two temperature handswhere severe corrosion will occur: around theacid dew point, where concentrated acidschemically attack the metal, and around the waterdew point, at which point the acids are muchdiluted and become even more corrosive.
All fuels display this pattern, but the upper or aciddew point temperature depends on the amountof sulphur present in the fuel (Figure 24). In orderto prevent corrosion becoming a significantproblem, either in the boiler or in the exit flue andchimney, a temperature above the acid dew pointmust be maintained. Most modern three-pass shellboilers have flue gas exit temperatures around200ºC and, except when firing a clean fuel (i.e.natural gas, LPC or gas oil), it is uneconomic toattempt heat recovery.
10.3.5.1 ECONOMISER INSTALLATION
Flue gas economisers have been in use for a longtime on both shell and water tube boilers of olderdesign. Most of these consist of large cast iron heatexchangers. Cast iron is used because it is moreresistant to the acid corrosion, which is inevitableat start-up and shut-down. Figure 25 shows asimple schematic of a boiler economiserarrangement.
Much simpler but less efficient economisers have
also been installed. These consist basically of awater jacket round the stack.
The increase in overall thermal efficiencyachievable by using recovered heat to increase thefeedwater temperature is shown in Figure 26. Ingeneral, for every 1ºC increase in feedwatertemperature there is an approximate drop of 4ºCin the flue gas temperature.
In the case of clean fuels with a minimal sulphurcontent it is possible for flue gas exit temperaturesto be below the water dew point temperaturewithout causing significant corrosion problems, asshown earlier for condensing boilers. Acondensing economiser is merely an extension ofthis principle.
The introduction of an economizer into the boilerbreeching will increase the pressure drop in theflue gas system. In a forced draft boiler, this maymean the installation of a new forced draft fan, orat least a new impeller and motor. The resultantincrease in combustion chamber pressure maynecessitate changes to the burner. In an induceddraft system, the induced draft fan may bechanged, but the combustion chamber pressureand burner will remain the same.There will be anadditional water-side pressure loss that may meana modification to the boiler feed pumps andmotors. The temperature of the gas to the stackwill be less, which reduces the stack draft.Feedwater piping modifications, economizersupport, and possible breeching modificationsmust be evaluated.
Example
The analysis that follows is based on the actual addition of a free standing economizer to a forced draftpackaged water-tube boiler producing a maximum of 20 000 kg/h of superheated steam at 3100 kPa(gauge).
The natural gas fired boiler operated with 10 per cent excess air, 300˚ C gas outlet temperature and a
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tested efficiency of 80 per cent. Before conversion, the boiler’s annual fuel consumption was 292 780 GJat a cost of R42.4/GJ.The modification included changes to the F.D. fan, burners and feed pump motors.The total cost of the project was reported to be R1 580 000 (1984).
Annual fuel cost before conversion = 292 780 GJ x R42.40/GJ= R12 413 870
After conversion, the excess air was still 10%, but the exit flue gas temperature had decreased to 180ºC.The reduction in the flue gas heat loss would be equal to 4.8 per cent. An additional radiation loss of 0.2per cent of the fuel input can be allowed for the economizer heat transfer efficiency of approximately 96per cent.Thus, the heat recovered in the economizer = 4.8 - 0.2 = 4.6 per cent of fuel input.
Annual steam heat = 292 780 x 0.8
= 234 224 GJ
Fuel energy after conversion = 234224Fuel energy after conversion =Fuel energy after conversion = (0.80 + 0.046)
= 276 860 GJ
Annual fuel cost after conversion = 276 860 x 42.4
= R11 738 860
Annual fuel savings = R12 413 870 – 11 738 860= R675 010
Simple payback = R1580000Simple payback =Simple payback = R675010
= 2.34 years
Generally the potential for energy saving will depend on both the type of boiler installed and the fuel used.For a typical older-model shell boiler with a flue gas exit temperature of 260ºC an economiser couldreduce temperatures to 200ºC, increasing the feedwater temperature by 15ºC and raising the overallthermal efficiency by 3%. For a modern three-pass shell LTHW boiler firing natural gas with a flue gas exittemperature of 140ºC a condensing economiser would reduce the exit temperature to 65ºC, giving anincrease in thermal efficiency of 5%. An economiser must be correctly sized so that the heat transfer doesnot cause the water temperature to exceed the system operating temperature or to be flashed off tosteam.
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Figure 23:Typical corrosion curve for fuel oil. (Source: ETSU)(Good Practice Guide 30. Page 88. Figure 54.)
Figure 24: Flue gas dew point versus fuel sulphur content. (Source: ETSU)(Good Practice Guide 30. Page 88. Figure 55.)
Figure 25: Schematic of an economiser. (Source: ETSU)(Good Practice Guide 30. Page 88. Figure 56)
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10.3.6 COMBUSTION AIR PRE-HEAT
Combustion air pre-heat has always beenregarded as the poor cousin of the economiserbecause air pre-heaters are large and less efficientoverall. In order to improve thermal efficiency by1% the combustion air temperature must beraised by 20ºC. Furthermore, most gas and oilburners used on boiler plant were not designedfor high air pre-heat temperatures and amaximum increase of 50ºC is usually all that canbe tolerated.
The usual heat sources for combustion air pre-heating include:
• heat remaining in the flue gases:
• higher temperature air drawn from thetop of the boiler house:
• heat recovered by drawing the air over orthrough the boiler casing to reduce shelllosses.
The two latter sources tend to be the most
commonly used as they require little additionalequipment.
When considering an airheater, the burnermanufacturer should be consulted to determinethe maximum allowable combustion air tempe-rature. This could be as low as 250ºC, and it isunlikely to be higher than 400ºC since that wouldrequire alloy steels instead of carbon steel.
The introduction of an airheater will increase thepressure loss on the flue gas and combustion airsystems. A forced draft system, with only a singleF.D. fan, may require the insulation of a new fanand motor. For a balanced draft system, both fansmay have to be replaced, although a new impellerand motor might be sufficient. The forced draftsystem may also include modifications to theburner, as the combustion chamber pressure willincrease significantly. New air and gas ductworkmust be installed, and modifications to the stackmay be necessary.
Modern burners are, however, available which canstand much higher combustion air pre-heat
Figure 26: Feed-water temperature and boiler efficiency. (Source: ETSU)(Good Practice Guide 30. Page 89. Figure 58.)
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temperatures. It is therefore possible to considerinstalling a heat exchanger in the exit flue as analternative to an economizer. Figure 27 shows theenergy-saving potential of this technique.
The combustion air intake can sometimes berelocated to the top of the boiler house to useheated air and save energy, as in the example thatfollows.
10.3.7 LOAD SCHEDULING
When a boiler is being operated at low loadssome of the losses remain constant and are notdependent on the firing rate. Shell losses resultingfrom radiation and convection, for instance, remainlargely the same whether the burner is operating
or not, so a boiler having a shell loss equivalent to2% of fuel fired at full firing will have a lossequivalent to 6% at one third firing.
At lower firing rates the flame does not fill thefurnace chamber so heat transfer rates fall.This iscompensated for in the reduced flue gas velocitythrough the convection tubes.
In the case of fuels containing significant sulphurcontent, continuous firing below 30% of ratedboiler output may result in boiler metaltemperatures falling below the sulphur dew point.This, in turn, can cause smutting and, possibly, rapidcorrosion.
The best practice is to use boilers that willoperate at 60% or more of their rating under
EXAMPLE
A boiler firing No.2 oil uses 14 500 kg/h of air at 20ºC average temperature. Installation of a duct to thetop of the boiler house increases the average air temperature to 30ºC.The specific heat of the air is 1.01kJ/kg·ºC.
Heat recovered = 14 500 kg/h x (30 - 20)ºC x 1.01 kJ/kg·ºC
= 146 450 kJ/h
The boiler operates 6000 hours per year, and the fuel costs R50/GJ.
Annual fuel savings = 146 450 x 6000 x 50Annual fuel savings =Annual fuel savings = 1 x 10
6
= R43 930 per year
The ducting cost is R100 000.Simple payback = R1000000Simple payback = = 2.3 yearsSimple payback = R43930
Generally, the savings achieved will depend on the type of system installed. Ducting hot air from the topof the boiler house typically results in savings of 1%, while savings of 2% are more typically achieved bydrawing combustion air over/through the boiler casing.
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normal firing conditions. For LTHW and MTHWsystems this is easily achieved using a modular boilersystem. For steam boilers, however, the solution isnot so simple since, in many cases, each boiler israted to meet the plant’s maximum loadrequirement. Where the steam is used for processand space heating there will be a significantreduction in load once the space heating is turnedoff in summer.A smaller boiler, correctly sized for thesummer load should therefore be installed.This alsoapplies in the case of lame hot water systems.
Steam systems that have low base loads but highpeak demands over relatively short periods alwayscause fuel efficiency problems. Older boilers had avery high thermal storage capability because oftheir very high water content, but modernpractice produces boilers with many more tubesand much less water. In some cases, therefore, asmaller boiler firing at a steady higher rate into asteam accumulator as shown in Figure 30 is amore thermally efficient solution.
Figure 27: Efficiency increase versus air pre-heat. (Source: ETSU)(Good Practice Guide 30. Page 91. Figure 59.)
Figure 28: Schematic of a steam accumulator. (Source: ETSU)(Good Practice Guide 30. Page 84. Figure 52.)
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Matching the load can result in a thermal efficiencyimprovement of around 2%. The cost savingresulting from the prevention of sulphur corrosionby proper load scheduling may be much greater.
10.3.8 ON-LINE CLEANING
Metal surfaces in the path of the combustion gasesneed regular cleaning to remove sooty deposits,especially when firing solid fuels. Soot blowers ofvarious kinds have been used to remove soot anddust both from shell and water tube boilers andfrom economisers and air pre-heaters.Traditionallythese comprised high-speed steam or compressedair jets, but recent developments have producedinfra-sound and ultra-sound units. The correctinstallation and use of soot blowers reducesmaintenance and retains the optimum efficiency ofthe plant over an extended period.
Incorrect water treatment can lead to scaleformation, which is a much better insulator thansoot or ash. It is not only lack of water treatmentthat causes the problem, however. In manyinstances, over enthusiasm in adding treatments,on the basis that ‘a bit more will be even better’,leads to the formation of insulating coatings on thewater side of heat transfer surfaces.
Incorrect water treatment, poor combustion andpoor cleaning schedules can easily reduce overallthermal efficiency by 2%. However, the additionalcost of maintenance and cleaning must be takeninto consideration when assessing savings.
10.3.9 FLUE SHUT-OFF DAMPERS
For situations where boilers are regularly shutdown because of changes in load, the heat losscaused by the chimney effect drawing cold airthrough the boiler can be significant. This is
particularly true when a number of boilers areconnected to a common header and are operatedin a cascade manner.
The best-known solution is to install dampers inthe exit flues. In the past the main problemsencountered included designing dampers thatwere virtually gas tight, and incorporating a controlsystem that would prevent the boiler firing againsta closed damper.
Today, automatic gas-tight shut-off dampers forinstallation in a boiler exit flue are widely available(Figure 29). In the case of forced draught (FD) oiland gas burners a cheaper alternative is available,particularly for retrofit situations: this involves theinstallation of an automatic damper at thecombustion air fan inlet.
It is difficult to put an exact figure on the potentialsaving from shut-off dampers as each boilerinstallation has different operating parameters andoperating periods. A saving of 1% in fuelconsumption is, however, usually achieved.
10.3.10 VARIABLE SPEED FAN DRIVES
The overall potential of modem variable speeddrives has been widely explored. For large boilerplant fitted with induced draught (ID) fans, thecontrol of combustion air is generally achieved bythrottling the damper. These dampers, however,tend to be designed more for simplicity andreliability than for accurate control and most givea very poor control characteristic at the top andbottom of the operating range. Multi-opposed-bladed dampers and iris type dampers have muchbetter control characteristics.
If the load characteristic of the boilers is variable,it maybe economic to replace the dampers with avariable speed drive. However, up to now therehas been very little experience of using such driveswith individual boilers rated at up to 20 MW.
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10.3.11 INTEGRATED CONTROL
Major advances in control technology using themicroprocessor have entirely changed strategiesfor control. Historically each part of a process orplant was treated individually, the appropriatecontrols being fitted for temperature, flow etc.With microprocessor contacts, the process can beexamined as a whole, allowing all aspects to beoptimised simultaneously. This type of control isnow available for boiler plant.
The control can be as simple as the oxygen trimcontrol already mentioned or can involve acompletely integrated system that operates theboilers and all the associated equipmentautomatically. The only limit to the amount ofinformation that can be gathered is the number ofsensors and signal converters installed. Equallythere is no limit to the number of plant items thatcan be controlled using the information collected.
The advantages of a centralised control system arenumerous, and include the following:
• faults are recognised and reported morequickly;
• a decline in performance is recognised atan earlier stage; and
• maintenance scheduling can beincorporated into the system.
The automatic control of plant items begins withthe boiler and combustion system: this can bedesigned to include sequencing of the boilers toensure that the correct number of boilers of anappropriate capacity is on line to meet theexpected demand. This will maximise overallefficiency.The water treatment equipment will alsobe subject to automatic control, normally includingthe automatic regeneration of ion exchange beds.Outside the boiler house, changes in processrequirements, reflected in the rate at whichtemperature or pressure varies, can be used toanticipate the extent of future load swings.
The only limit to such a system is the imaginationof the control designer. However, not all thefunctions of a sophisticated controller need by
Figure 29: Schematic of a flue shut-off damper and interlock. (Source: ETSU)(Good Practice Guide 30. Page 86. Figure 53.)
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used: they can simply be there for application asand when required.
10.4 WHAT TO DO FIRST –A QUICK CHECKLIST
The boilerhouse is very often the largest singleuser of energy on a site, and it is important that itsperformance is under constant review. Thereshould be a comprehensive boilerhouse loggingprogramme in place, which includes themonitoring of the following parameters:
• fuel consumption;• heat output;• flue gas conditions;• make-up water consumption;• subsidiary electricity consumption.
The frequency of checks will depend on the plantand manpower availability, but weekly orpreferably daily checks should be made. Animportant measure of the performance of a boilerplant is the specific boiler efficiency.This is the ratiobetween useful heat production and energyconsumed, i.e.:
Heat transferred to heating medium:(usually steam or water) x 100%
Fuel Input
The heat transferred to the heating mediumcannot normally be determined directly, thoughindirect measurements, such as fluid temperatures,pressure and volume flow rates can be used.Electronic combustion analysers can be used tocheck efficiencies and monitor trends, particularlybefore and after maintenance.
In addition it is always worth undertaking a morecomprehensive boilerhouse audit, to highlight heatlosses and take into account subsidiary energyusage.The biggest part of this exercise is to assess
the portion of the primary fuel energy lost in theboilerhouse. The main heat losses for a typicalinstallation, in order of importance, are:
• flue gas losses;• heat losses from boilerhouse heat
distribution system;• blowdown losses;• heat losses from boiler shell;• ash losses (coal-fired plant);• fuel heating (oil-fired plant).
Methods which can be used to assess these lossesare detailed in “Saving Energy and Money”booklets which cover, amongst other things, theeconomic use of oil-fired, gas-fired and coal-firedboiler plant respectively.
A significant amount of electrical energy is used inthe typical boilerhouse for circulating pumps,combustion fans, etc. Where a dedicated kWhmeter is installed for the boilerhouse this shouldbe read regularly, though an estimate of electricityconsumption can be determined from motorduties and running hours if necessary.
Make-up water consumption should bemonitored to give early warning of system leaks.The recovery of uncontaminated condensate onsteam systems should be maximized, saving onenergy, water and chemicals. Where there aresignificant year round requirements for processheating, typically in excess of 5,000 hours/annum,the feasibility of combined heat and power (CHP)should be investigated.
10.4.1 CHECK LIST
• Maintain efficient combustion.• Maintain good water treatment.• Repair water and steam leaks.• Recover heat from flue gas and boiler
blowdown whenever possible.• Ensure good operational control and
•
59
consider sequence control for multi-plantinstallations.
• Attempt to match boilers to heatdemand. Valve off idle boilers to reduceradiation losses.
• Use flue dampers where appropriate tominimize flue losses when plant not firing.
• Ensure that boilers and heat distributionsystems are adequately insulated.
• Blowdown steam boilers only whennecessary.
• Ensure as much condensate as practicableis recovered from steam systems.
• Insulate oil tanks and keep steam orelectric heating to the minimum required.
11. TYPES OF FURNACES
• • • • • • • • • • • • • •The purpose of a process furnace is to apply heatto the contents in a controlled manner. Thefurnace may be used for heating metals to aprecisely controlled temperature for heattreatment, or for melting. Furnaces aremanufactured in many different types and sizes,some of which are described in this section.
Furnaces may be batch or continuous type.Furnaces, which generate heat by burning fuel, maybe of the direct or indirect fired types. Furnacesare also heated from electric resistance heaters.
11.1 BATCH FURNACES
Batch furnaces process the product in batches,which means that the furnace doors must beopened and closed at the beginning and end ofthe batch cycle. Since this is a significant source ofenergy loss, the loading and unloading timesshould be minimized. It is also important to loadthe furnace completely to minimize the energyloss per unit of product.
Figure 31 shows a crucible melting furnace usedfor nonferrous metals. Metal scrap is loaded intothe furnace in batches, and the molten metaltapped off as required.
Figure 30 shows a high temperature electricfurnace used for the heat treatment of steel.
11.2 CONTINUOUSFURNACES
Continuous furnaces process the productcontinually by moving it through the heating zoneson chains or conveyors. Since the loading andunloading doors are open all or part of theoperating time, there is a significant heat lossthrough these openings. Continuous furnaces alsomay have a significant heat loss because of theconveying mechanism, which is heated to theoperating temperature with the product. If theconveyor cools off outside the furnace before re-entering the loading area, the energy required toheat the conveyor is not used productively.Thus, it
•
•
60
is better if the conveyor stays within the heatedfurnace area.An example of this type of furnace isshown in figure 32.
11.3 DIRECT FIREDFURNACES
The products of combustion are in direct contact
with the product being heated in a direct firedfurnace.The heat transfer process from the flameto the product is more effective than with anindirect heated furnace, where the flue gas is notin direct contact with the product.The higher rateof heat transfer which can be achieved with directfired furnaces can lead to local surface overheatingof the product, unless the furnace temperature isproperly controlled.
•
Figure 30: High Temperature Electric Box furnace. (Source: Canadian Gov.)(Energy Management Series 7. Page 25. Figure 15.)
Figure 31: Crucible furnace. (Source: Canadian Gov.)(Energy Management Series 7. Page 25. Figure 14.)
61
11.4 INDIRECT HEATEDFURNACES
In indirect heated furnaces the products ofcombustion are not in direct contact with theproduct being heated (Figure 33). Heat istransferred through some form of heat exchanger.
This type of furnace may be used to provide acontrolled environment for oxidizing or reducing,by introducing an ar tificial atmosphereindependent of the combustion process. Since theheat transfer from the flame to the product is notas effective as the direct fired furnace, it can beexpected that the flue gas temperature will be
higher, resulting in higher heat losses unless heatrecovery is used.
There are a few special considerations for indirectfired furnaces, which affect the heat balancecalculations. If a controlled atmosphere ismaintained inside the furnace, the heat input andoutput of the gas entering and leaving the furnacemust be included in the heat balance. If heat isrequired for the preparation of the atmosphere,the energy required in the gas generator must beincluded as part of the total heat input to thefurnace. Electrical energy used for refrigeration orother purposes in the gas generator must also beincluded.
Figure 32: Continuous type furnace. (Source: Canadian Gov.)(Energy Management Series 7. Page 25. Figure 14.)
•
62
12.1 POTENTIAL LOSSES5
As with boilers, to optimise the operation offurnace plant it is necessary to understand whereenergy wastage is likely to occur.
12.1.1 FURNACE ENERGY BALANCE
Basically the furnace energy balance is similar to a
boiler energy balance. Energy is taken into thefurnace from:
• The fuel. This includes both the heat ofcombustion and the heat carried in as afunction of the fuels temperature.
• Combustion air. This air entering thecombustion chamber contains heat as aresult of its temperature.
• The ‘feed’. Whatever it is that is to beheated contains heat as a result of itstemperature.
Figure 33:An indirectly heated furnace. (Source: Canadian Gov.)(Energy Mangement Series 7. Page 13. Figure 7.)
• • • • • • • • •
12. ENERGY AND COSTSAVINGS FOR FURNACES
• • • • • • • • •
•
5A furnace energy efficiency test is described in the appendix.This gives the ‘direct method’ for evaluating efficiency, and a breakdown of the losses.
63
Energy is then lost from the furnace in variousforms:
• Flue gas. The products of combustionleave the furnace at a temperature higherthan incoming fuel and combustion air.
• Surface heat transfer. As the furnacetemperature is higher than thesurrounding environment heat is lost fromthe combustion zone to the environmentas a result of conductive, radiative and/orconvective heat transfer.
• Escaping furnace air. If the internalpressure of the furnace is too high hotgases will escape to the surroundingsthrough leaks, openings and doors.Conversely if the pressure on the insideof the furnace is higher than thesurroundings then ‘cold’ air will be drawninto the furnace, requiring additional heatto maintain a steady furnace temperature.
12.2 MINIMIZING FURNACELOSSES
12.2.1. FLUE GAS HEAT LOSS
The same comments apply here as applied to
boilers and have been included in the section oncombustion.
The major influencing factors are the exit flue gastemperature and the degree of excess air present.Fuel preparation should be correct(uncontaminated and at the right temperature),burners undamaged and properly maintained, andcombustion air (both primary and secondary)should be introduced at the right rate and withadequate turbulence.
12.2.1.1 EXCESS AIR REDUCTION
A continuous O2 and Combustibles analyser is thebest arrangement, but the cost is high. Samplingtests with an Orsat or other chemical means canbe a reliable guide to proper combustionconditions. Readjustment of the fuel/air ratiocontrol should be performed promptly if required.
Below table 8 and 9 give a list of typical excess airratios for various fuels and typical savings that canbe realized through excess air adjustment.
Classification Standard air ratioMelting furnace for metal casting 1.3Steel slab continuous reheating furnace 1.25Metal reheating furnace other than steel 1.3slab continuous reheating furnaceContinuous heat treating furnace 1.3Gas generator and gas reheating furnace 1.4Petroleum refinery furnace 1.4Pyrolyzer and reformer 1.3Cement baking furnace 1.3Alumina baking furnace and lime baking 1.4furnaceContinuous glass melting furnace 1.3
Table 8: Standard air ratio for Industrial furnace
•
64
Furnace Air ratio Air ratio after correctiontemperature before 1.40 1.30 1.20 1.10 1.00(˚C) correction
700 1.70 11.6 14.9 17.9 20.8 23.4
1.60 7.72 11.1 14.3 17.3 20.1
1.50 3.86 7.43 10.7 13.8 16.7
1.40 –– 3.76 7.27 10.5 13.5
1.30 –– –– 3.65 7.01 10.1
1.20 –– –– –– 3.48 6.74
1.10 –– –– –– –– 3.38
900 1.70 18.7 23.5 27.7 31.5 34.9
1.60 12.5 17.6 22.2 26.3 29.9
1.50 6.23 11.7 16.6 21.0 25.0
1.40 –– 5.94 11.3 16.0 20.2
1.30 –– –– 5.66 10.7 15.2
1.20 –– –– –– 5.29 10.1
1.10 –– –– –– –– 5.06
1100 1.70 30.8 37.3 42.6 47.1 51.0
1.60 20.6 28.0 34.1 39.3 43.7
1.50 10.3 18.6 25.6 31.4 36.4
1.40 –– 9.43 17.3 23.8 29.4
1.30 –– –– 8.67 15.9 22.1
1.20 –– –– –– 7.91 14.7
1.10 –– –– –– –– 7.36
1300 1.70 55.0 61.9 67.1 70.9 74.0
1.60 36.7 46.5 53.6 59.1 63.4
1.50 18.3 31.0 40.2 47.3 52.9
1.40 –– 15.7 27.2 35.9 42.7
1.30 –– –– 13.7 23.9 32.1
1.20 –– –– –– 11.9 21.3
1.10 –– –– –– –– 10.7
Table 9: Calculated values of % saving
65
12.2.1.2 INSTALL A HEAT
EXCHANGER IN THE FLUE
GAS OUTLET
The cost of heat exchangers is significantly affectedby the temperature of the gas entering the unit.Careful consideration should be given tointroducing cold air into the gas stream, if required,to lower the gas temperature enough to useeconomic materials. Stainless steels or alloyscannot be used for temperatures above 950ºC.
If the recovered heat is used to preheat thecombustion air, the burner manufacturer shouldbe consulted to determine the maximumallowable air temperature. Frequently, this will beas low as 250ºC. It is unlikely to be higher than400ºC since that would require alloy steels insteadof carbon steel. If it is not practical to heat thecombustion air, it may be possible to heat processwater or to install a waste heat boiler to utilize thebeat energy in the flue gas.
Introduction of a heat exchanger will increase thepressure drop in the flue gas system, which meansthat the combustion air fan capacity will bereduced. It may be necessary to install a new fanor impeller and drive motor. It is possible that thefurnace pressure will be increased unless there issufficient draft available from the stack toovercome the added resistance across the heatexchanger. Because of these and other possiblecomplications, it is suggested that the furnacemanufacturer or a consulting engineering firm beretained to make an evaluation of the proposedchanges.
The economic and technical analysis that follows isbased on an actual installation of high-alloyrecuperators applied to an indirectly heated,continuously operating, heat-treating furnace. Acustom-designed triple-pass recuperator wasbolted to the exhaust leg of each of the 24 radianttube heaters of the furnace, and each of the
existing induced draft burners was replaced with asealed positive pressure burner. The modificationalso included a blower system for the supply ofcombustion air, and improvements to the controlsto reduce excess air from 15 to 20 per centbefore conversion to 8 to 10 per cent.Total costof the project was R1 200 000.
Before conversion, the fuel consumption perburner was measured at 193 000 kJ/h, or 4.63 GJ/hfor the furnace with all burners in service. Thefurnace operates 6 days per week, 24 hours perday and the allowance for down time or part loadoperation is 15 per cent. Gas costs R42.40 pergigajoule.Annual fuel cost before conversion= (100 – 15)= x 24 h/d x 6 d/wk x 52 w/yr
100x 4.63 GJ/h x 42.4/GJ
= R1 249 490
To estimate the savings, it is necessary todetermine the recuperator performance. Flue gasleaves the radiant tubes at 1100ºC, and enters therecuperator at this temperature. The gas leavesthe recuperator at 650ºC and the combustion airis heated from ambient to 500ºC.
To isolate the performance of the recuperatorfrom other savings, it is assumed that excess airbefore and after conversion remains at 20 percent. The intersection of 20 per cent excess airand 1100ºC on Figure 5 (extrapolated) indicatesthat 64 per cent of the heat supplied in the fuel islost in the flue gas.
Flue gas heat loss/burner= 64Flue gas heat loss/burner= x 193 000Flue gas heat loss/burner= 100
= 123 500 kJ/h
The remainder, or 69 500 kJ/h, enters the furnacethrough the radiant tube.
After conversion the stack gas temperaturedropped to 650ºC. Using 20 per cent excess air
66
and 650ºC flue gas temperature shows that about40 per cent of the heat supplied is lost, and 60 percent enters the furnace. It is reasonable to assumethat the amount of heat entering the furnacethrough each radiant tube does not change whena recuperator is installed, as the gas temperatureleaving the tube remains at 1100ºC. Sixty per centof the heat supplied per burner after conversion,equals 69 500 kJ/h.Burner energy = 69 500 = 115 800 kJ/hBurner energy = = 115 800 kJ/hBurner energy = 0.6 = 115 800 kJ/h
Flue gas heatloss/burner = 115 800 - 69 500
= 46 300 kJ/hEnergy savings = 24 (burners)
x (123 500 - 46 300)= 1 852 800 kJ/h= 1.85 GJ/h
Savings = 1,85Savings = x 100Savings = 4.63
= 40%
The actual fuel consumption savings were 48 percent. Part of the discrepancy is because of thedifficulty of measuring flue gas temperatures andairflows, hence excess air quantities accurately.Themodification introduced two further areas ofpotential savings. One of these was the improvedairflow control and the resulting reduction inexcess air to 8 per cent.
The second area of savings results from thechanges made to the control system and this isdifficult to estimate. Before conversion, burnerswere operated at a fixed setting and turningselected burners on and off controlled furnacetemperature. Heat was lost from the furnace toradiant tubes not in service, because of naturalconvection of outside air through these tubes.Thisloss was eliminated with the new modulatingcontrol system.
The annual fuel savings were 48 per cent of R1249490 or about R600 000. Based on the capital cost
of R200 000 the payback period for this projectwas 2 years.
12.2.2 HEAT LOSS TO INCOMPLETE
COMBUSTION
This is discussed in the section on combustion. Animportant aspect of this is the proper mixing offuel and combustion air in the furnaces burner.
Burner Assembly
It is good practice to have an experienced burnermanufacturer’s representative set up the burneradjustments. Furnace operators can then identifythe appearance of a proper burner flame forfuture reference. The flame should be checkedfrequently, and always after any significant changein operating conditions affecting the fuel,combustion air flow, or furnace pressure hasoccurred.
The installation of a modern design burnerassembly can permit operation at lower values ofexcess air, thus reducing stack losses.A new burnerassembly can also be the means to provide fullautomation for start-up and shutdown. In amultiple burner installation automation will permitstart-up and shutdown of burners to followvarying load patterns, rather than modulating theload on individual burners over a wide range.Burners generally operate more efficiently at highloads, so improvements in part load economy canbe expected if some burners are shut down.
Provision should be made to shut off thecombustion air to idle burners. This avoids lossesdue to excess air entering the furnace and nottaking part in the combustion process.
12.2.3 RADIATION HEAT LOSS
The same comments that were made for boilers
67
apply here.The radiation heat loss of a furnace isprimarily a function of the applied thermalinsulation. Insulation reduces the heat radiatingfrom the boiler and maintains the outside surfacesat a temperature low enough for safety.The qualityand thickness of the insulation on the varioussections of the furnace are normally determinedby the surface temperature. Most safetyregulations require that metal surfaces withinreach of personnel not exceed 50ºC.The heat lossfrom the casing is difficult to measure accurately.
Re-insulating Furnace Enclosure
Older furnaces may use refractory brick for thefurnace lining. If the furnace has to be rebuilt, it isfrequently economical to use ceramic fibre blanketinsulation. If refractory brick is required towithstand rough handling, an outer layer ofceramic fibre can be used.
Since ceramic fibre is a much better insulator thanrefractory brick, care should be taken to ensurethat the inner layer of refractory is notoverheated, since its average temperature will behigher. During a tour of a plant it is noticed that afurnace appears to be radiating substantialquantities of heat. Temperature measurements ofthe surface average 200ºC on the walls and 250ºCon the roof.The outside dimensions of the furnaceare 2 m by 2 m by 6 m long. It is decided toreinsulate the furnace to give a maximum surfacetemperature of 50ºC, to provide operator safetyand heat savings.
Taking heat losses as 21.5 MJ/(m2.h) at 250ºC,11.6 MJ/(m2.h) at 200ºC, and 1.7 MJ/(m2.h) at50ºC.
Roof area = 2 m x 6 m= 12 m
2
Wall area = (2m x 6m x2) + (2m x 2m)= 32 m
2
Heat loss before reinsulation
= [21.5 MJ/(m2·h) x 12 m2] + [11.6 MJ/(m2·h)x 32 m2]
= 692.2 MJ/h
Heat loss after reinsulation= 13 MJ/(m2·h) x (12 m2 + 32 m2)= 74.8 MJ/h
Note that the heat loss to the floor is notconsidered to be significant.
Energy savings = 692.2 - 74.8 MJ/h= 617.4 MJ/h
The furnace operates 4000 hours per year, andfuel costs R50/GJ.
Annual savings = 617.4 MJ / h x 4000 h / yr x R50 / GJAnnual savings = Annual savings = 1000 MJ / GJ
= R123 480/yr
12.2.4 FURNACE PRESSURE CONTROL
Maintaining a slight positive furnace pressure cancontrol air leakage into or gas leakage out of afurnace.The control damper in the furnace flue gasducting or the related control should bereadjusted if the furnace pressure is not at thecorrect value.
Replace Warped or Damaged Furnace Doors orCovers
Furnace doors or covers, which are warped,damaged or missing can be a source ofconsiderable leakage of air into or gas out of thefurnace. Doors or covers with tight fitting sealsshould replace these. Further improvement wouldresult from installing power operators on thedoors to minimize the time the doors are open, aswell as make it easier for the operators.
68
The following example illustrates the possiblesaving by replacing a missing door.A 0.25 m2 dooris noted to be missing from a furnace operating at900ºC. Heat radiated through the opening is 400MJ/(m
2.h). The furnace operates 4000 hours per
year and fuel costs R50 per GJ.
Annual heat loss = 0.25 m2 x 400 MJ/(m2.h)x 4000 h
= 400 000 MJ/yr= 400 GJ/yr
Annual savings = R50 x 400= R20 000/yr
This saving will be reduced slightly by the heat lossfrom the closed door. Some additional savings mayresult from the elimination of air leaking into orgas escaping from the open door.
12.2.5 FURNACE EFFICIENCIES AND
MONITORING AND
TARGETING
High temperature process plant, such as furnacesand kilns, are used in a variety of industries.Thereis a wide range of plant used, and it may be of acontinuous or batch nature. However, the basisunder which an energy audit is undertaken on allhigh temperature processes is very similar.
As with boilers, a specific efficiency for the processplant can be calculated but it is more usual to usethe specific energy consumption:
Specific energy consumption= Energy consumption
Product throughput
This gives a good measure of the relative plantperformance, and requires only good productionrecords and energy consumption figures to bekept.
Efficiency for furnaces will be defined as theamount of heat taken up by the product versusthe heat added in the form of fuel. For a furnace itis important to estimate and trend the changes ofefficiency over time. Due to the nature of theprocess, efficiencies are far smaller than those fora boiler. A small change in efficiency will result in alarge change in specific fuel consumption. Anychanges are therefore important. In the appendixthe ‘direct method’ for furnace efficiencycalculations is outlined for a furnace of any kind.
As regards monitoring equipment the, minimumsuggested is to have the ability to determine theenergy used per unit of output, so that significantdeviations from this can be identified andcorrective action taken.The fuel or watt meter canbe a portable instrument which may be used onseveral furnaces.Additional instrumentation wouldbe required to identify individual losses.Measurement of flue gas temperature and oxygencontent can be used to indicate flue gas loss. If aheat exchanger is used to recover heat from theflue gas, temperature measurements of the gasand air in and out of the heat exchanger can beused to check the performance.
Relocate Combustion Air Intake to Recover HeatWithin the Building
Heat generated inside the plant tends to rise,resulting in significant temperature differencesbetween floor and ceiling. If the furnace has aforced draft fan it is often possible to installlightweight ducting from the ceiling to the fanintake. Alternatively, the ducting may be routed toan adjacent shop if considerable heat issimultaneously being generated and ventedoutside. Care should be taken to size the ductingadequately to minimize the pressure drop.
A furnace using 5000 kg/h of combustion airdraws inside air at 20ºC average temperature.Installation of a duct to the ceiling increases theaverage air temperature to 30ºC.
69
Heat recovered = c x DT x w= 1.006 kJ/(1Kg·ºC)
x (30 - 20)ºC x 5,000 Kg/h= 50 300 kJ/h
The furnace operates for 6000 hrs per year andthe fuel costs R50/GJAnnual fuel savings = 50 300 x 6000 x 50Annual fuel savings =Annual fuel savings = 1 x 10
6
= R15 090 per year
The cost of the ducting is R15 000.Simple payback = R15 000
R15 090= 1.0 year
RECOVERY OF HEAT FROM EQUIPMENTCOOLING WATER
It is often possible to use the warm waterdischarge from equipment coolers for purposessuch as process washing. In some systems thewater discharge may be too cool to be useful. Inthese instances the installation of a water flowcontrol valve and temperature controller may behelpful.The water flow is controlled automaticallyfrom the water temperature at the cooler outletso that the water temperature is high enough tobe useful, while maintaining proper cooling. Thecontrol system will also reduce water use.
12.3 WHAT TO DO FIRST – AQUICK CHECKLIST.
In a well controlled plant there should be a goodcorrelation between energy consumption andproduction rate.The more scatter on the graphicalplot the worse the process control.The offset onthe graph, i.e. the energy consumption at zeroproduction, represents the level of standing losses.These are typically made up of:
• flue gas losses (except on electricallyoperated plant);
• structural heat losses;• heat loss by radiation from openings;• loss of furnace gases at openings;• heat loss to conveyers, rollers, etc;• heat loss to charging equipment and
mechanisms;• heat removed by cooling circuits.
It is worth measuring or calculating the level ofthese heat losses to identify areas for potentialimprovement.
• Minimise heat losses from openings, suchas doors, on sealed units.
• Use high efficiency insulating materials toreduce losses from the plant fabric.
• Attempt to recover as much heat aspossible from flue gases. The pre-heatingof combustion air or stock or its use inother services such as space heating arewell worth considering.
• Reduce stock residence time to aminimum to eliminate unnecessaryholding periods.
• Ensure efficient combustion of fuelswhere applicable.
• Avoid excessive pressure in controlledatmosphere units.
• If maintaining stock at high temperaturefor long periods, consider the use ofspecialized holding furnaces.
• Make sure excessive cooling of furnaceequipment is not occurring.
• Ensure the minimum amount of stocksupporting equipment is used.
• Ensure there is effective control overfurnace operating parameters –computerized control should beconsidered for larger units.
6Specific fuel consumption is the ratio of fuel consumed to kg of
product heated. • • • • • • • • •
•
70
APPENDIXCONVERSION TABLES.
• • • • • • • • •Table A1: Mass Equivalent
FROM/TO KILOGRAM METRIC TON (USA) TON (UK) OUNCE POUND POUNDTON (a) (b) (c) (USA) (UK)MULTIPLY BY1 Kilogram 1.000 1.000x10
-31.102x10
-39.842x10
-43.527x101 2.205 2.425x10
3
1 Metric 1.000x103
1.000 1.102 9.842x10-1
3.527x104
2.205x103
2.425x103
ton (a)1 Ton 9.072x10
29.072x10
-11.000 8.929x10
-13.201x10
42.000x10
32.200
(USA) (b)1 Ton (UK) 1.016x10
31.016 1.120 1.000 3.584x10
42.240x10
32.464x10
3
(c)1 Ounce 2.835x10
-22.835x10
-53.124x10
-52.790x10
-51.000 6.251 6.873x10
2
1 Pound 4.536x10-1
4.536x10-4
5.000x10-4
4.464x10-4
1.600x10-1
1.000 1.100(USA)1 Pound 4.124x10
-14.124x10
-44.545x10
44.059x10
-41.455x10
19.083x10
-11.00
(UK)
(a) Also referred to overseas as “tonne”(b) Also referred to overseas as “short ton”(c) Also referred to overseas as “long ton”
Table A2:Volume Equivalent
FROM/ LITER CUBIC GALLON GALLON BARREL PINT PINT CUBICTO METRE (USA) (UK) (USA) (USA) (UK) FOOTMULTIPLY BY1 Litre 1.000 1x10
-32.642x10
12.200x10
-16.289x10
-32.113 1.760 3.531x10
-2
1 Cubic 1x103
1.000 2.642x102
2.200x102
3.289 2.113x103
1.760x103
3.531x101
metre1 Gallon 3.785 3.785x10
-31.000 8.327x10
-12.381x10
-28.000 6.662 1.337x10
-1
(USA)1 Gallon 4.546 4.546x10
-31.201 1.000 2.860x10
-29.606 8.000 1.605x10
-1
(UK)1 Barrel 1.590x10
21.590x10
-14.200x10
13.498x10
11.000 3.360x10
22.799x10
25.615
(USA)1 Pint 4.732x10
-14.732x10
-41.250x10
-11.041x10
-12.976x10
-38.328x10
-18.328x10
-11.671x10
-2
USA1 Pint 5.683x10
-15.683x10
-41.501x10
-11.250x10
-13.574x10
-31.0001 1.0001 2.006x10
-1
(UK)1 Cubic 2.832x10
12.832x10
-27.481 6.231 1.781x10
-14.984x10
14.984x10
11.000
foot
71
Steam generators boiler heat balance andefficiency calculations
The calculation of the efficiency of a boiler involvesa comparison between the energy supplied in thecoal with the energy transferred to the feedwaterto convert it to superheated steam.
The heat balance on the other hand concerns the
identification of the magnitude of all the heat flowsinto and out of the boiler.
It is therefore possible to calculate the efficiency ofa boiler in one of two ways:-
1) The Direct Method where the energy gain of theworking fluid (water and steam) is comparedwith the energy content of the boiler fuel;
Table A3: Energy and Heat Equivalent
FROM/TO JOULE CALORIE THERM BTU THERMIE ERG kWh
MULTIPLY BY
1 Joule 1.000 2.388x10-1
9.479x10-9
9.478x10-4
2.389x10-7
1.000x107
2.788x10-7
1 Calorie 4.187 1.000 3.968x105
3.968x10-3
1.001x10-6
4.187x107
1.163x10-6
1 Therm 1.055x108
2.520x104
1.000 1.000x105 2.521x101 1.055x1015
2.930x101
1 BTU 1.055x103
2.520x102
1.000x10-5
1.000 2.521x10-4
1.055x1010
2.930x104
1 Thermie 4.186x106
9.995x105
3.967x105
3.967x103
1.000 4.186x1013
1.163
Erg 1.000x107
2.388x108
9.479x10-16
9.478x10-11
2.398x10-14
1.000 2.778x10-14
kWh 3.600x106
8.599x105
3.413x10-2
3.412x103
8.600x10-1
3.600x1013
1.00
Table A4: Multipliers and Equivalents
1 Toe 42Gj
1 Tse 29.3 Gj
• • • • • • • • •
boiler efficiency test
• • • • • • • • • • • • • •
72
2) The Indirect Method where the efficiency is thedifference between the losses and the energyinput.
Before these two methods are discussed in moredetail, it is necessary to define the terminologyused.
Calorific Value (CV) - The energy released by afuel when it is completely burnt and when theproducts of combustion are cooled to the originalfuel temperature is known as the calorific value ofthe fuel.
The combustion of any fuel with hydrogen as aconstituent produces water vapour. If the productsof combustion are at a high temperature, thewater will leave the system as vapour and willcarry with it the energy represented by the energyof superheated steam. However, if the gases arecooled, the vapour will condense and reject thisenergy.
Thus it is possible to have two distinctly differentcalorific values for fuels containing hydrogen - thegross calorific value (GCV) and the net calorificvalue (NCV). The GCV assumes that the watervapour from combustion has been condensed toa liquid, while the NCV does not assumecondensation of the vapour.
Those in favour of the use of the lower CalorificValue argue that practical power cycles are notable to use the energy contained in the vapour,while those who prefer the Gross Calorific Valuefeel that this is a problem of the cycle rather thanone of the fuel.
By convention, it is common to use the GrossCalorific Value in boiler calculations.
Coal Analysis
Customary practice in reporting the componentsof a coal is to use two different analyses, known as
proximate analysis and ultimate analysis.
Proximate Analysis is defined as the determinationof moisture, volatile matter, and ash, and thecalculation of fixed carbon by difference.
Ultimate Analysis of a dried sample is defined asthe determination of carbon, hydrogen, sulphur,nitrogen and ash, and an estimate of oxygen bydifference.
Analysis on an as-received basis includes the totalmoisture content of coal received at the plant.Similarly, the as-fired basis includes the totalmoisture content of the coal as it enters the boilerfurnace or pulverises.
The Direct Method of Boiler EfficiencyCalculation
As mentioned earlier, the direct method consistsof a direct comparison between the fuel energyinput and the energy gain of the working fluid.
Energy Input = Coal Flow Rate x G.C.V.
Energy Output = Steam Flow Ratex Enthalpy Gain
Efficiency = Energy OutputEfficiency = Efficiency = Energy Input
Note that:-
1. The power requirements of the boilerauxiliaries (e.g. fans and pumps) are notnormally included in this calculation.
2. The accurate measurement of steam flow athigh temperatures and pressures is difficult andit is thus more common to measure the flowof feedwater to the boiler.
DIRECT METHOD EXAMPLE
Gross Calorific Value of the Coal = 27,32 MJ/kg
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Measured Values
Coal Flow 3,3kg/sFeedwater Flow 30,4kg/sFeedwater Temperature 175,4ºCSuperheater outlet temperature 450,0ºCSuperheater Outlet pressure 4,00 Mpa
Energy Input= Coal Flow Rate x Gross Calorific Value= 3,3 x 27 320= 90 156 kJ/s (Kw)
Energy Output= Steam Flow Rate x Enthalpy Gain= 30,4 x (3330 - 743) kJ/s= 78 644,8 kJ/s
Efficiency = Energy OutputEnergy Output
= 78 644,8 x 100%90 156,0
= 87,32 %
The Indirect Method of Boiler EfficiencyCalculation
In order to calculate the boiler efficiency via theindirect route, all the energy losses that occurwithin the boiler must be established.These lossesare conveniently related to the amount of fuelburnt (i.e. kilojoules per kilogram of coalconsumed or to the amount of energy supplied(i.e. losses as a percentage of the energy contentof the fuel). In this way it is easy to compare theperformance of differently rated boilers.
For the purposes of illustration, typical values,which would have been obtained from a boilerefficiency test, are included below and these valuesare used to demonstrate the equations derived forthe boiler losses.
Ultimate Analysis of the Coal (% by mass)
Carbon 64,6%Hydrogen 4,0%Oxygen 7,0%Ash 14,4%Moisture – Inherent 3,4%
-Superficial 4,1%Nitrogen 1,0%Sulphur 1,5%
100%Gross Calorific Value 27,32MJ/kg
Flue Gas Analysis
CO2 14,9%CO 0,4%O2 4,4%N2 80,3%
100,0%
Measured Values
Carbon in ash 12,87%Flue Gas Outlettemperature 139,0 ˚CAmbient Dry Bulb AirTemperature 30,0 ˚CAmbient Wet Bulb AirTemperature 22,0 ˚C
The various losses associated with the operationof a boiler are discussed below.
Energy Loss Due to Unburned Carbon
Small amounts of carbon will be left in the ash andthis constitutes a loss of potential heat in the fuel.To assess these heat losses, samples of ash must beanalysed for carbon content. The quantity of ashproduced per unit of fuel must also be known.With this information, the unburned carbon losscan be expressed as:-
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Quc = mash CVc Ca………..(1)Where Quc = Unburned Carbon Loss
(kilojoules/kg fuel)mash = Ash Content of Fuel
(kilograms/kilogram)CVc= Calorific Value of Carbon
(33 820 kJ/kg)Ca = Carbon content of the ash,
expressed as a fraction of the totalash quantity.
EXAMPLE 1
Quc = mash CVc Ca
= 14,4 x 33820 x 12,87= x 33820 x = 100 x 33820 x 100= 626,78 kJ/kg of coal
or = 626,78or = x 100%or = 27 320
= 2,29%
Mass of unburnedcarbon = mash Ca
= 0,144 x 0,1287= 0,0185 kg carbon/kg fuel
Energy Loss due to the Dry Flue Gas
There is an energy loss associated with the factthat the nitrogen, which enters the boiler as aconstituent of the combustion air, leaves the boilerat a higher temperature. Additionally, the gaseouscombustion products leave the boiler at anelevated temperature. This energy is lost to thesystem.
This is the greatest boiler loss in a correctlyoperated system and can be calculated with thefollowing formula:
Gfd = mg cp (Tg – Ta) …..(2)
where Qfd = Dry Flue Gas Loss(kilojoules/kg fuel)
mg = Mass Flow of Gas(kg gas per kg of fuel)
cp = Specific Heat of the Gas. Theapproximate value for dry air canbe used (1,005kJ/kg ºC)
Tg = Temperature of the gas leavingthe boiler (ºC)
and Ta = Temperature of the gas enteringthe boiler (ºC)
It will be seen from the above formula that thelosses are directly proportional to the gas flow andto the temperature difference of the gas acrossthe boiler. Consequently, any increase in the excessair quantity will increase the magnitude of this loss.
On the other hand, a reduction in thetemperature difference will reduce the loss. Toachieve this reduction, economizers and airheaters are used to reduce the exhaust gastemperature, while the inlet air suction is oftensituated in the warm region of the power station,immediately below the roof.
The above equation relates the Dry Flue Gas Lossto the mass flow of gas.To calculate the efficiency,it is necessary to relate this loss to the mass of fuelburned. In other words, we need to know howmuch gas one kilogram of fuel will generate.
In the ideal case:
Carbon in Fuel Process Carbon in flue gas
All the carbon in the fuel is converted in the boilerinto gas which contains carbon, in the form ofC02.Therefore over a given period of time:-
Carbonin = % Carbon in the fuel x mass of fuelCarbonout = % Carbon in the flue gas x mass of
flue gas
Since carbon cannot be destroyed, Carbonin
= Carbonout
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� % Carbon in fuel x mass of fuel = % Carbon influe gas x mass of flue gasor Mass of flue gas = % Carbon in fuel
Mass of fuel % Carbon in flue gas
In other words:-
Kilograms Dry Flue GasKilograms Fuel= % by weight of carbon in the fuel
% by weight of carbon in dry flue gas
As shown above, not all the carbon is burnt andsome of it remains in the ash.Therefore instead ofreferring to the weight of carbon in the fuel, theweight of carbon consumed should be used andthe above equation becomes:-
Kilograms Dry Flue GasKilograms Fuel= % by weight of carbon consumed
% by weight of carbon in dry flue gas
A further correction is required to improve theaccuracy of this equation. At the moment theequation ignores the fact that sulphur burns to SO2.The easiest way of including the sulphur in the fuelis to add the “carbon equivalent” of sulphur to thecarbon consumed. It can be proved that as far as theproduction of flue gas is concerned, sulphurproduces less gas than carbon in the ratio of 12 to32 (the molecular weights of the two elementsconcerned).The above equation then becomes:-
Kilograms Dry Flue GasKilograms Fuel= % carbon consumed + sulphur x 12/32= % by weight of carbon in dry flue gas …(3)
The next problem is to establish the percentageby weight of carbon in dry flue gas.Without goinginto the proof, it can be shown using Avogadro’slaw (which implies that masses of equal volumesof gases will be proportional to their molecularweights) that:-
The mass of carbon in 1 kg of dry flue gas
= 12 CO2 + 12 CO …(4)= …(4)= 44 CO2 + 32O2 + 28CO + 28N2 …(4)
where C02, CO, O2 and N2 refer to the percentagevolumes of the components in the flue gas.
Substituting equation (4) into equation (3), it ispossible to calculate the kilograms of dry flue gasproduced for each kilogram of fuel burnt.
Multiplying this answer by equation (2) (the dryflue gas loss in terms of flue gas flow), enables theDry Gas Loss per mass of fuel burnt to beestablished.
EXAMPLE 2
The mass of carbon in 1 kg of flue gas
= 12 CO2 + 12 CO …(4)== 44 CO2 + 32O2 + 28CO + 28N2 …(4)= 12 x 14,9 + 12 x 0,4== 44 x 14,9 + 32 x 4,4 + 28 x 0,4 + 28 x 80,3= 0,0601 kg carbon I kg flue gas
Mass of carbon in 1 kg of fuel = 0,646 kgCalculated mass of unburntcarbon = 0,0185 kgTherefore mass of carbonconsumed = 0,6275 kg
Carbon Equivalent of Sulphur= Percentage sulphur x 12= Percentage sulphur x = Percentage sulphur x 32
= 1,5 x 12100 32
= 0,0056Mass of Dry Gas per kg of Fuel
= Carbon Consumed+ Carbon Equivalent of Sulphur
Carbon in the Flue Gas
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= 0,6275 + 0,00560,0601
= 10,53 kg dry gas/kg fuelBut Qfd = mg cp (Tg – Ta)
= 10,53x 1,005 x (139 - 30)= 1 153,96 kJ/kg fuel
or = 1153,96 x 100 %27 320
= 4,22 %
Energy Loss Due to Evaporating and Superheatingthe Moisture in the Fuel
Moisture entering the boiler with the fuel leaves asa superheated vapour. This moisture loss is madeup of the sensible heat to bring the moisture toboiling point, the latent heat of evaporation of themoisture, and the superheat required to bring thissteam to the temperature of the exhaust gas.Thisloss can be expressed in the following
Qcm = mw [cpw (Tsat – Ta) + hfg
+ cps (Tg – Tsat)] …(5)
where Qcm = Fuel Moisture Loss(kilojoules/kg fuel)
mw = Moisture (kg moisture/kg fuel)cpw = Specific heat of water (kJ/kgºC).
A value of 4,18 is typical over thetemperature range of interest.
Tsat = The saturation temperature atwhich the water evaporates.For the sake of simplicity, thistemperature is assumed to be1OOºC.
hfg = The latent heat of evaporation ofwater at 1000C and 1 bar.(2 258 kJ/kgºC).
cps = Specific heat of steam (kJ/kgºC).A value of 2,01 corresponding toa temperature of 100ºC can beused.
Tg = Temperature of the gas leavingthe boiler (ºC)
Ta = Temperature of the gas enteringthe boiler (ºC)
EXAMPLE 3
Qcm = mw [cpw (Tsat – Ta) + hfg
+ cps (Tg – Tsat)]
Moisture in the fuel = (3,4 + 4,1)100
= 0,075 kg moisture/kg fuelQcm = 0.075 x [4,18 x (100-30)
+ 2 258 + 2,01x (139-100))
= 197,17 kJ/kg fuelor = 19717 x 100%
27320= 0,72 %
Energy Loss Due to Evaporating and Superheatingthe Moisture Formed by the Combustion ofHydrogen
The combustion of hydrogen causes a heat lossbecause the product of combustion is water. Thiswater is converted to steam in the boiler and thiscarries away heat, particularly because of its latentheat content.
The chemical equation for the reaction betweenhydrogen and oxygen is:-
2H2 + O2 = 2 H2O
Considering molecular weights; 4 + 32 = 36
In other words, 1 kg of hydrogen will produce 9 kgof water. The equation for the hydrogen loss cantherefore be expressed as follows:-
Qhf = 9 mh [cpw (Tsat – Ta) + hfg
+ cps (Tg – Tsat)] (6)where Qhf = Fuel Hydrogen Loss
(kilojoules/kg fuel)mh = Hydrogen in the Flue Gas
(kg hydrogen/kg fuel)cpw = Specific heat of water (kJ/kgºC).
A value of 4,18 is typical over thetemperature range of interest.
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Tsat = The saturation temperature atwhich the water evaporates.For the sake of simplicity, thistemperature is assumed to be1OOºC.
hfg = The latent heat of evaporation ofwater at 100ºC and 1 bar.(2 258 kJ/kgºC).
cps = Specific heat of steam (kJ/kgºC).A value of 2,01 corresponding to atemperature of 1OOºC can beused.
Tg = Temperature of the gas leaving theboiler (ºC)
Ta = Temperature of the gas enteringthe boiler (ºC)
EXAMPLE 4
Hydrogen in the fuel = 4,0 %
Moisture produced by combustion of H2 as % offuel = 4,0 x 9
= 36% or 0,36 kg moisture/kg fuelQhf = 9 mh [cpw (Tsat – Ta) + hfg
+ cps (Tg – Tsat)]- 0,36 x (4,18 x (100-30) + 2 258
+ 2,01 x (139-100)]- 946,44 kJ/kg fuel
or = 946,44 x 100%27320
- = 3,46%
Energy Loss Due to Incomplete Combustion
Products formed by incomplete combustion couldbe mixed with oxygen and burned again with afurther release of energy. Such products includeCO, H2, and various hydrocarbons and aregenerally only found in the flue gases from olderchain-grate boilers. Carbon monoxide is the onlygas whose concentration can be determinedconveniently in a power plant test.
While it is relatively easy to determine the
volumetric percentage of carbon monoxide in theflue gas, as in the case of the dry gas losses, it isnecessary to relate CO to the mass of fuel burnt.The energy loss can then be calculated bymultiplying the mass of CO by its calorific value(10143 kJ/kg)
In equation (3), the mass of dry flue gas wasrelated to the mass of fuel burnt. i.e.
Kg Dry Flue GasKilograms Fuel= % carbon consumed + % sulphur x 12/32
% by weight of C in dry flue gas
If % carbon consumed + % sulphur x12/32 = A,then the above equation can be rewritten as:-
K Dry Flue GasKilograms Fuel= A …(7)= Weight of C in dry flue gas
Weight of dry flue gas
Using Avogadro’s law once again, it can be shownthat the ratio of CO to the weight of dry flue gasis:-
= 28COweight of dry flue gas
Multiplying both sides of equation (7) by this ratioyields:-
Left-Hand Side
Kg Dry Flue Gas x Kilograms CO = Kilograms COKilograms Fuel Kg Dry Flue Gas Kilograms Fuel
Right-Hand Side
= A x weight of dry flue gas x 28COWeight of C in dry flue gas weight of dry flue gas
= A x 28COWeight of C in dry flue gas
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Hence: -
Kilograms CO = (% carbon consumed+ % sulphur x 12/32)x 28 CO
Kilograms Fuel 12CO2 + 12CO
Multiplying this value by the calorific value ofcarbon monoxide (10 143 kJ/kg) loss due tocarbon monoxide per kilogram of fuel burnt.
EXAMPLE 5
The percentage of carbon monoxide in 1 kg offuel
= (% carbon consumed + % sulphurx 12/32) x 28 CO
12CO2 +12CO
= (62,75 + 1,5 x 12/32) x 28 x 0,412 x 14,9 + 12 x 0,4
= 3,86 %or = 0,0386 kg CO/kg fuel
Calorific Value of CO = 10 143 kJ/kgCO Heat Loss/kg fuel = 10 143 x 0,0386
= 391,74 kJ/kg fuelor = 391 74 x 100%
27320= 1,43 %
Energy Loss Due to Superheating Vapour in theCombustion Air
Vapour, in the form of humidity in the incoming air,is superheated as it passes through the boiler.Since this heat passes up the stack, it must beincluded as a boiler loss.
This loss is given by the following formula:-
Qfm = cp (Tg – Ta) (9)Where Qfm = Air Vapour Loss (k i lo jou le s / kg
vapour)
cp = Specific Heat of the Vapour(kJ/kgºC).A value of 2,01, corresponding to atemperature of 100ºC can be used.
Tg = Temperature of the gas leaving theboiler (ºC)
and Ta = Temperature of the gas enteringthe boiler (ºC)
To relate this loss to the mass of coal burned, themoisture content of the combustion air and theamount of air supplied per unit mass of coalburned must be known.
The mass of vapour that air contains can beobtained from psychrometric charts and typicalvalues are included below:
Dry-Bulb Wet Bulb Relative KilogramHumidity Water per
Temp ºC Temp ºC (%) kilogramDry Air
20 20 100 0,01620 14 50 0,00830 22 50 0,01440 30 50 0,024
The materials entering a boiler for combustionpurposes are the fuel and the combustion air.Thetotal mass of the products of combustion musttherefore equal the sum of the mass of the fueland air.The products of combustion consist of wetflue gas and ash. Hence:-
Mass of (Fuel + Air)= Mass of (Wet Flue Gas + Ash)
or
Mass of Air = Mass of (Wet Flue Gas + Ash - Fuel)
The wet flue gas mass is the sum of the mass of
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the dry gases plus the moisture contained in thefuel and the moisture from the combustion ofhydrogen.
EXAMPLE 6
From psychrometric charts, at 30ºC dry bulbtemperature and 22ºC wet bulb temperature, therelative humidity is 50% and the moisture contentof the air is 0,014 kg/kg.
Qfm = cp(Tg – Ta)= 2,01 x (139 – 30)= 219,09kJ/kg vapour
or = 219,09 x 0,014kJ/kg of dry air enteringboiler
= 3,07kJ/kg
Mass of Air = Mass of (Wet Flue Gas+ Ash – Fuel)
Mass of dry gas/kg fuel = 10,53 kg/kg(from Example 2)
Moisture in fuel = 0,075 kg/kg(from Example 3)
Moisture from H2 = 0,36 kg/kg(from Example 4)
––––––
Total Wet Gas/kg fuel = 10,97 kg/kgTotal Ash Content 0,144 kg/kg
(from Analysis)Total fuel burnt 1 kg (by definition)
Therefore Mass of Air = 10,97 + 0,144 – 1= 31,03 kJ/kg fuel
Combustion AirMoisture Loss = 10,11 x 3,07 kJ/kg fuel
31,03 kJ/kg fuelor = 31,03 x 100 %
273200,11 %
Radiation and Unaccounted Losses
The remaining heat losses from a boiler consist ofthe loss of heat by radiation from the boilercasting into the surrounding boiler house.Additionally, the losses associated with theincomplete combustion of the fuel to hydrogenand hydrocarbons in the flue gas are includedhere. Further, there can be a sensible heat lossfrom the hot ash which leaves the boiler.
In a relatively small boiler, with a capacity of 10MW, the radiation and unaccounted losses couldamount to between 1% and 2% of the grosscalorific value of the fuel, while in a 500 MWboiler, values of between 0,2% and 1 % are typical.
Radiation and unaccounted boiler losses. Lowercurve for radiation only is based on data in theAmerican power test code. The unaccountedlosses are primarily due to moisture in thecombustion air and sensible heat in the refuse.They could be larger particularly if unburnt gasesare present but not detected.
Heat Balance
Having established the magnitude of all the lossesmentioned above, a simple heat balance will givethe efficiency of the boiler. The efficiency is thedifference between the energy input to the boilerand the heat losses calculated.
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BOILER HEAT BALANCE
EXAMPLE SOLUTION
Ultimate Analysis of the Coal (% by mass)
Carbon ____%Hydrogen ____%Oxygen ____%Ash ____%Moisture – Inherent ____%
- Superficial ____%Nitrogen ____%Sulphur ____%
100%
Gross Calorific Value ____ MJ/kg
Flue Gas Analysis
CO2 ____%CO ____%O2 ____%N2 ____% (or by difference)
100,0%
Measured Values
Carbon in ash ____%Flue Gas Outlet temperature ____ºCAmbient Dry Bulb Air Temperature ____ºCAmbient Wet Bulb Air Temperature ____ºC
Unburnt Carbon Loss
Mass of unburnedcarbon = massash % x Carbonash %
100 100= ____ x ____
100 100= ____ kg carbon/kg fuel
Unburnt CarbonLoss = kg C/kg Fuel x CVcarbon
_____ x 33 820 kJ/kg fuelor = Carbon Loss x 100%
GCV of fuel= ______ x 100= ____%
Dry Flue Gas Loss
The mass of carbon in 1 kg of flue gas
= 12 CO2% + 12 CO%44 CO2% + 32O2% + 28 CO% + 28 N2%
= 12 x + 1244 x ____ + 32 x ____ + 28 x ____+ 28 x ____
= ______ kg carbon / kg flue gas
Loss due to:- KJ/kg fuel %
1) Unburnt Carbon in Ash 626,78 2,29
2) Dry Flue Gas 1153,96 4,22
3) Moisture in the Fuel 197,17 0,72
4) Moisture from Hydrogen 946,44 3,46
5) Incomplete Combustion (CO Loss) 391,14 1,43
6) Moisture in the Combustion Air 31,03 0,11
7) Radiation and Unaccounted Losses 273,20 1,00
TOTAL LOSSES 3619,20 13,23
BOILER EFFICIENCY i.e. (100% - LOSSES) 86,77%
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Mass of carbon in 1 kg of fuel = ____kgCalculated mass of unburnt carbon = ____ kgTherefore mass of carbon consumed = ____kg
Carbon Equivalent of Sulphur= Percentage sulphur x 12/32
= ____ x 12100 32
= ____kg
Mass of Dry Gas per kg of Fuel
= Carbon Consumed+ Carbon Equivalent of Sulphur
Carbon in the Flue Gas= +
_______= ____ kg dry gas / kg fuel
But Qfd = massgas x cp x (Tgas – Tambient air)
= ____ x 1,005 x (____ - ____)= ________kJ / kg fuel
or = ______ x 100 %____
= _____%
Moisture in the Fuel
Qcm = mw [cpw (Tsat – Ta) + hfg + cps (Tg – Tsat)]
Moisture in the fuel = ( % + %)100
= _____ kg moisture/kg fuelQcm = _____ x [4,18 x (l00 - ___) + 2 258
+ 2,01 x (___ - l00)]= ______ kJ/kg fuel
or = _______ x l00%____
= ____%
Hydrogen Loss
Hydrogen in the fuel = _____%
Moisture produced by combustion of H2 as % offuel= _____ x 9= _____% or _____ kg moisture/kg fuel
Qhf = 9 mh [cpw (Tsat – Ta) + hfg+ cps (Tg – Tsat)]
= _____x [4,18 x (l00 - ___) + 2 258+ 2,01 x (___ - l00)]
= ______ kJ/kg fuelor = _____ x 100 %
___= ______ %
Incomplete Combustion
The percentage of carbon monoxide in 1 kg offuel
= (% carbon consumed + % sulphurx 12/32) x 28 CO
12CO2 + 12CO= ( + x 12/32) x 28 x
12 x ____ + 12 x ____= ____ %
or = ____ kg CO/kg fuelCalorific Value of CO = 10 143 kJ/kgCO Heat Loss/kg fuel = 10 143 x _____
= ______ kJ/kg fuelor = _____ x 100 %
___= ____ %
Moisture in the Combustion Air
From psychrometric charts, at _____ dry bulbtemperature and ______ wet bulb temperature,relative humidity is ___%and the moisture contentof the air is _____ kg/kg.
Qfm = cp (Tg – Ta)= 2,01 x (___ - ___)= _____ kJ/kg vapour
or = ____ x ____ kJ/kg of dry airentering boiler
= ____kJ/kg
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Mass of Air
Mass of dry gas/kg fuel = Mass of (Wet FlueGas + Ash - Fuel)
Moisture in fuel= _____ kg/kgMoisture from H2 = _____ kg/kg
Total Wet Gas/kg fuel = _____ kg/kgTotal Ash Content = _____ kg/kg
(from Analysis)Total fuel burnt = 1 kg (by
definition)
Therefore Mass of Air = _____ + _____ -1= _____ kg dry air/kg
fuelCombustion AirMoisture Loss = _____ x _____ k J / k g
fuel= _____ kJ/kg
fuelor = _____ x 100 %
___= ____ %
Loss due to:- KJ/kg fuel %
1) Unburnt Carbon in Ash ––– –––
2) Dry Flue Gas ––– –––
3) Moisture in the Fuel ––– –––
4) Moisture from Hydrogen ––– –––
5) Incomplete Combustion (CO Loss) ––– –––
6) Moisture in the Combustion Air ––– –––
7) Radiation and Unaccounted Losses ––– –––
TOTAL LOSSES ––– –––
BOILER EFFICIENCY i.e. (100% - LOSSES) –––
BOILER HEAT BALANCE
• • • • • • • • •
83
The following gives a ‘direct method’ methodologyfor calculating the efficiency of a heating furnace. Itis more simplified than the boiler example givenabove due to the range of different furnaceconfigurations, where constant heating and coolingmake it difficult to calculate the ‘non-steady’ lossesexplicitly.
The energy required to heat any material is givenby the mass, M, multiplied by the specific heat, Cp,multiplied by the temperature rise. The energyrequired to heat a solid with specific heat Cpsfrom Tos to some final temperature Tfs istherefore:
energy to heat solid = M Cps (Tfs - Tos)
The energy required to melt a material at itsmelting temperature is the mass, M, multiplied bythe latent heat of melting, Lm:
energy to melt material at melting temperature = MLm
The energy required to raise the temperature ofa liquid is analogous to that of the solid and is themass, M, multiplied by the specific heat of theliquid, Cpl, multiplied by the temperature rise fromthe starting temperature, Tol, to the final liquidtemperature,Tfl. So:
energy melt to final temperature = M CPl (Tfl - Tol)
Calculating the process efficiency:
Energy is delivered at some efficiency which,because this is a straight line, clearly is notdependent on the amount of material beingprocessed and can be expressed as a constant, e.
If the process, as in the aluminium melting furnace,is taking the material through from solid to liquid,the temperature range is continuous and the finalsolid temperature Tfs and the starting liquidtemperature,Tol are both the melting temperature,Tm. The overall energy requirement to heat fromsolid at temperature Tos to liquid at Tfl is:
Energy = M Cps (Tm – Tos) + Lm + Cpl (Tfl – Tm)Energy = Energy = e
M is a common term and a graph of energy vs.production is expected to be a straight line ofslope, m, where:
m = Cps (Tm – Tos) + Lm + Cpl (Tfl – Tm)m =m = e
A value of m can be determined from the graph.Cps,Tm, Lm and Cpl are characteristics of the materialand can be looked up in reference books.Tos andTfl, the initial and final temperatures, are processparameters of which management should alreadybe aware.
Everything in this expression except the efficiency,e, is known.
The slope of the line e is 2.585 Gj/te. Take thepouring temperature to be 730ºC. The specificheat capacity of aluminium from ambienttemperature to the melting point at 661ºC is1.061 kJ/kg/º0 and for the liquid is 1.177 kJ/kg/ºC.The latent heat of melting is 396 kJ/kg.
slope = 1.06 x (661 – 25) + 396 + 1.177 )760 – 661) = 1,152slope = 1.06 x (661 – 25) + 396 + 1.177 )760 – 661) = 1,152slope = e e
The efficiency of the furnace is therefore:
furnace efficiency test
• • • • • • • • • • • • • •
84
e = 1,152e = 1,152 = 45%e = 2,585
This level of efficiency is quite good for a gas-firedfurnace in this application.
Selecting specific heat data
It is important to select the right data on specificheats. Specific heats vary with temperature and,where not specified, tend to be quoted inreference texts at, or around, 25ºC (298ºK). Thiscan be rather misleading - particularly in hightemperature processes. Heat capacity is oftenquoted in reference texts as the molar heatcapacity, which is the energy required to raise onegram-molecular weight (the molecular weightexpressed in grams) by 1ºC. So, to convert this toa kg basis, divide by the molecular weight andmultiply by 1,000. To calculate the molecularweight of a material, add the atomic weights of its
constituent elements in the proportions of itschemical formula.
Note: Very precise information (which is usuallythe best to use) on heat capacities, and thetemperature ranges over which they are valid, isoften provided in reference texts as the numericalvalues of coefficients A. B. C and D in an equationof the form:
Cp = A + BT + C + DT2Cp = A + BT + C + DT2Cp = A + BT + T2 + DT2
For some materials it may be necessary to useseveral such formulae to cover the range oftemperatures required. For comprehensiveinformation on specific heats, latent heats of fusionand evaporation. Specialist textbooks on theprocesses in use in specific industries usually alsoprovide this information.
• • • • • • • • •
85
• • • • • • • • • • • • • •SOURCES OF
FURTHER
INFORMATION
For the latest news in energy efficiency technology:
“Energy Management News” is a free newsletter issued by the ERI, whichcontains information on the latest developments in energy efficiency inSouthern Africa and details of forthcoming energy efficiency events.
Copies can be obtained from:
The Energy Research InstituteDepartment of Mechanical EngineeringUniversity of Cape TownRondebosch 7700Cape TownSouth AfricaTel No: (+27 21) 650 3892
Fax No: (+27 21) 686 4838
Email: [email protected]