How To Save Energy And Money

How to save energy and money

Guide Book 2 BOILERS & FURNACES

STRATEGY

ENERGY EFFICIENCY EARNINGS

STRATEGY

N

RG

Y

MI E

RA

E

3E

Netherlands Ministery of Economic Affairs

EUROPEAN COMMISSION

LS

AND

EN

TSI

Technical Services International

•••••••••••••• HOW TO SAVE ENERGY AND MONEY IN BOILERS AND FURNACE SYSTEMS

• This booklet is part of the 3E strategy series. It provides advice on practical ways of improving energy efficiency in boilers and furnace systems. Prepared for the European Commission DG TREN by: The Energy Research Institute Department of Mechanical Engineering University of Cape Town Rondebosch 7700 Cape Town South Africa www.eri.uct.ac.za This project is funded by the European Commission and co-funded by the Dutch Ministry of Economics, the South African Department of Minerals and Energy and Technology Services International , with the Chief contractor being ETSU. Neither the European Commission, nor any person acting on behalf of the commission, nor NOVEM, ETSU, ERI, nor any of the information sources is responsible for the use of the information contained in this publication The views and judgements given in this publication do not necessarily represent the views of the European Commission

HOW TO SAVE ENERGY AND MONEY IN BOILERS AND FURNACE SYSTEMS

••••

•••••••••••••• HOW TO SAVE ENERGY AND MONEY IN BOILERS AND FURNACE SYSTEMS

• Other titles in the 3E strategy series: HOW TO HOW TO HOW TO HOW TO HOW TO HOW TO

SAVE SAVE SAVE SAVE SAVE SAVE

ENERGY AND ENERGY AND ENERGY AND ENERGY AND ENERGY AND ENERGY AND

MONEY:THE 3E STRATEGY MONEY IN ELECTRICITY USE MONEY IN STEAM SYSTEAMS MONEY IN COMPRESSED AIR SYSTEMS MONEY IN REFRIGERATION MONEY IN INSULATION

Copies of these guides may be obtained from: The Energy Research Institute Department of Mechanical Engineering University of Cape Town Rondebosch 7700 Cape Town South Africa Tel No: (+27 21) 650 3892 Fax No: (+27 21) 686 4838 Email: [email protected] Website: http://www.3e.uct.ac.za

ACKNOWLEDGEMENTS

•

The Energy Research Institute would like to acknowledge the following for their contribution in the production of this guide: • Energy Technology Support Unit (ETSU), UK, for permission to use information from the “Energy Efficiency 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.

Guide Book Essentials: 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. Many more 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 worth considering. 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 control should be considered for larger units.

Table of Contents 1. INTRODUCTION............................................................................................................................................................................................1

2. COMBUSTION ..................................................................................................................................................................................................1 2.1 Combustion air.........................................................................................................................................................................................1 2.1.1 Excess Air.....................................................................................................................................................................................4 2.1.2 Glue Gas Analysis....................................................................................................................................................................4 2.1.3 Determination of Excess Air ............................................................................................................................................5 2.2 Heat losses ..................................................................................................................................................................................................7 2.2.1 Heat loss due to incomplete combustion................................................................................................................8

3. HEAT TRANSFER ...........................................................................................................................................................................................10 3.1 Conduction...............................................................................................................................................................................................10 3.2 Convection................................................................................................................................................................................................11 3.3 Radiation.....................................................................................................................................................................................................12 4.THE FUELS...................................................................................................................................................................13 4.1 Pipeline gas................................................................................................................................................................................................13 4.2 Liquid Petroleum Gas ........................................................................................................................................................................14 4.3 Fuel Oil........................................................................................................................................................................................................14 4.4 Coal .........................................................................................................................................................................................................15 4.5 Choice of Fuel ........................................................................................................................................................................................16 5. COMBUSTION EQUIPMENT: OIL AND GAS BURNERS..............................................................................18 5.1 Gas Burners .............................................................................................................................................................................................18 5.2 Oil Burners...............................................................................................................................................................................................18 5.2.1 Pressure Jet ..............................................................................................................................................................................18 5.2.2 Air or Steam Blast Atomiser ...............................................................................................................19 5.2.3 Rotary Cup ..............................................................................................................................................................................19 5.2.4 Low Excess Air Burners ...................................................................................................................................................19 5.3 Burner Controls....................................................................................................................................................................................19 6. COMBUSTION EQUIPMENT: SOLID FUEL COMBUSTION .......................................................................21 6.1 Stokers.........................................................................................................................................................................................................21 6.2 Chain Grate Stoker.............................................................................................................................................................................21 6.3 Sprinkler Stoker.....................................................................................................................................................................................22 6.4 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. INTRODUCTION

•••••••••••••• The guide then moves on to savings in furnaces. Various types of furnaces and energy saving measures are described. The emphasis here is on savings from excess air reduction, combustion air preheat, correct insulation and furnace pressure control.

This guide examines the energy savings potentials for boilers and selected furnaces. The boiler section starts with a description of different boilers plant, combustion equipment used and fuels available. Environmental impacts are described, boilers selection processes outlined and finally a list of measures and a strategy outline for saving energy in boiler operation.

2. COMBUSTION

••••••••• exposed directly to the heat generated in the combustion chamber, flue gas heat or a gas/fluid that has been heated by the combustion process.

In all aspects of boilers and furnaces (including dryers and kilns) heat is produced from combustion or by the use of electrical energy.The heat is transferred to the product or water to produce stream in the case of a boiler.

2.1 COMBUSTION AIR •

The fuel (with the exception of electricity which heats an element) burns in the ‘combustion chamber’, which varies in shape and size depending on the application. Common fuels include pipeline gas, liquid petroleum gas, heavy fuel oil, lighter oils and solid fuels such as biomass or coal. If gas is produced ‘on site’ this can also be used.

Stoichiometric air represents the amount of air required for complete combustion with the perfect mixing of the fuel and air Stoichiometric air is sometimes called theoretical air. If perfect mixing is achieved, every molecule of fuel and air takes part in the combustion process. Excess air must be supplied to ensure complete combustion of the fuel because perfect mixing of fuel and air does not occur. Percentage excess air is defined as the

The in the case of a furnace the product is then

1

minimum losses occur when the amount of air supplied is slightly greater than the “stoichiometric” amount.

total amount of combustion air supplied in excess of the stoichiometric air, expressed as a percentage of the stoichiometric air.

(

)

Total air = Stoichiometric air x (1 % Excess Airr) Total air = Stoichiometric air (x (1 + 100

The weight or volume of each element or compound in the fuel is required to determine the stoichiometric air. It is often inconvenient to determine stoichiometric air in this manner, as in many instances the precise fuel analysis is unknown or varies. A more convenient method is to determine the quantity of air per unit of heat in the fuel, i.e. kilograms of air per gigajoule of heat in the fuel as fired (kg/GJ). Expressed in this manner, the stoichiometric air required for common types of fuel is almost constant. Table 1 provides values for several different types of fuel, which may be used in boilers or furnaces.

The minimum amount of excess air required varies with the fuel used and the efficiency of mixing the air and fuel. If less than the minimum quantity of air is supplied, some of the fuel will not burn completely and there is a waste of fuel energy. Evidence of incomplete combustion usually shows up as carbon monoxide (CO) in the products of combustion (flue gas). A continuous gas analyser, or a manually operated Orsat, can be used to check for CO in the flue gas.

Figure 1: Zone of maximum combustion efficiency (Source: Canadian Gov.) (Energy Management Series 7. Page 4. Figure 2)

It may be suspected that a supply air fan, air inlet louvers, ducting or the air flow control method is inadequate. Knowledge of the required amount of furnace combustion air enables checking the adequacy of the air supply system.The combustion air requirements can be calculated and compared

Too much air also wastes energy. The gases leaving the furnace are hot and contain heat energy. If excessive amounts of air are supplied to the furnace, the excess will also be heated. The effect on heat losses by varying the amount of air supplied to the furnace is shown in Figure 1. The

2

is to operate the fuel valve and the damper with a common mechanical linkage. Some form of

to the capacity of the components in the air supply system.

Example: Combustion air requirements for a furnace using 700 l/h of Number 6 fuel oil, at 15 per cent excess air can be calculated. From Table 1, theoretical combustion air is 327 kg/GJ.The heating value of fuel oil with 2.5 per cent sulphur is about 42.3 MJ/L (sulphur content can usually be obtained from the fuel supplier). Combustion air requirement Combustion air requirement Combustion air requirement

= = = =

or =

700L/h x 42.3 MJ / L x 327 kg / GJ x 1.15 1000 MJ / GJ 11135 kg/h 11135 kg/h 3

1.204 kg / m 3 9248 m /h at standard conditions.

adjustable cam is used to vary the relative positions of the fuel valve and damper to provide proper fuel/air ratios at all firing rates.

Combustion air can be supplied to the equipment by natural or forced draft systems. Natural draft uses the negative pressure (draft) produced by the furnace stack to draw combustion air into the furnace and the resulting flue gases out of the furnace.The most common example of this is the ordinary domestic gas furnace. Natural draft is usually applied only to small furnaces with less than about one GJ/h heat input.

The combustion air fan also provides better mixing of the fuel and the air. The air is introduced into the furnace around the burner(s) and vanes, which produce a swirling motion in the air as it enters the furnace, can create turbulence. A highpressure drop between the air supply and the furnace is required to produce turbulence, and this can only be achieved with a forced draft system. These advantages mean that the excess air for a forced draft system can be lower than for natural draft firing, with resulting lower heat losses to the flue gas.

There are several disadvantages related to natural draft firing. The amount of combustion air drawn into the furnace cannot be controlled accurately and the fuel and air mixing is inefficient.This means that higher levels of excess air must be maintained to ensure that complete combustion is achieved under all conditions.The furnace pressure is always negative which allows air to leak into the furnace, and create additional flue gas volume and heat losses.

Forced draft firing permits a slightly positive furnace pressure at all times. Leaks will then be from the furnace outwards, which may lead to a dangerous situation when a furnace door is opened. Therefore, it is desirable to control furnace pressure at a slight positive value of not more than about 10 Pa. This is normally achieved by regulating a damper in the breeching between the furnace flue gas exit and the base of the stack.

Forced draft firing uses a fan to supply combustion air to the equipment. Airflow is regulated by means of dampers so that accurate control of the proportion of air to fuel for various firing rates is possible. A common method used to achieve this

3

monoxide (CO). Air contains nitrogen (N2) as well as oxygen (O2). The N2 does not take part in the combustion process, except for the formation of small quantities of nitrogen oxides (NOx).

It may not be possible to maintain furnace pressure as low as desired if heat recovery equipment is installed in the flue gas system or if the stack provides insufficient draft.

The major constituents of the products of combustion are water vapour, CO2, CO, N2, and any excess O2 left over from the combustion process. Not all of the constituents will be present in all instances. The presence of CO indicates incomplete combustion.

2.1.1 EXCESS AIR The actual percentage of excess air supplied to the furnace is one of the most informative items of information to the furnace operator. The most accurate way of determining this is to analyse the flue gas leaving the furnace.

Flue gas analysis can be determined by the use of

Figure 2: Combustion process. (Source: Canadian Gov.) (Energy Management Series 7. Page 6. Figure 3)

a continuous analyser or by periodic sampling.The sample should be taken as close to the furnace exit as possible to reduce air infiltration errors. Some continuous analysers measure O2 content and record or indicate the results. Other continuous analysers measure the combustibles content of the flue gas, which is mostly CO but may also include some unburned fuel in gaseous form. If a continuous flue gas analyser is not available, a sample of the flue gas can be taken and analysed with the use of an Orsat. The Orsat determines the percentage by volume of O2, CO2, and CO in the flue gas. The remaining gas is assumed to be N2, plus a small quantity of water

2.1.2 FLUE GAS ANALYSIS A furnace in which heat is produced by the combustion of fuel can be considered to have fuel and combustion air as inputs, and flue gas as the output (Figure 2). Practically all fuels used in furnaces are hydrocarbons, which contain the elements hydrogen and carbon. Although some fuels contain other constituents they are not usually important to the combustion process. The hydrogen 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

4

vapour, which did not condense out of the sample. There are other manually operated analysers available, which measure either CO2 or O2 in the flue gas.These are simpler to use and can be useful as a cross check against an Orsat.

% Excess air = % Excess air = % Excess air =

0.2682N2 – (O2 – 0.5CO)

Where O2 CO N2

oxygen by volume in flue gas (%) carbon monoxide by volume (%) nitrogen by volume (%)

= = =

O2 – 0.5CO

x 100

Figure 3: Excess air versus flue gas analysis. (Source: Canadian Gov.) (Energy Management Series 7. Page 7. Figure 4)

Examples: The flue gas analysis by volume on a furnace burning natural gas gives the following results: O2 = 9.8% CO2 = 6.2% CO = 0%

2.1.3 DETERMINATION OF EXCESS AIR

Flue gas analysis provides sufficient data to calculate the excess air to the furnace. In most furnaces, CO is absent or very low because of high levels of excess air. For natural gas or fuel oil firing with no CO in the flue gas, the per cent excess air can be determined from Figure 3. If other fuels are used or if CO is present, the following equation can be used:

From Figure 3, excess air is approximately 79 per cent. This number can be compared to the following calculation. %N2

5

= =

100% - (9.8% + 6.2% + 0%) 84%

% Excess Air % Excess Air % Excess Air

= 9.8 – (0.5 x 0) = x 100 = (0.2682 x 84) – [9.8 – (0.5 x 0)] = 77%

% Excess Air % Excess Air % Excess Air

This value is very high for a furnace burning natural gas, and the possibility of reducing the excess air level should be investigated.

This excess air is quite acceptable for a furnace burning coke-oven gas. In a furnace burning natural gas with a deficiency of air, the flue gas analysis is as follows.

Another example will provide greater familiarity with the calculation procedures. A furnace is burning coke-oven gas with the following flue gas analysis. O2 CO2 CO N2

= = = =

= 2.1 – (0.5 x 0) = x 100 = (0.2682 x 87.9) – [2.1 – (0.5 x 0)] = 9.8%

O2 CO2 CO N2

2.1% 10% 0% 87.9% (by difference)

= = = =

0% 11% 2% 87% (by difference)

Figure 3 cannot be used because of the presence of CO. % Excess Air % Excess Air % Excess Air

The equation should be used to calculate the excess air since Figure 3 is not applicable for cokeoven gas.

= 01 – (0.5 x 2) = = (0.2682 x 87) – [0 – (0.5 x 2)] = – 4.1%

x 100

Table 1: Combustion Air Requirements

Fuel

Stoichiometric kg/GJ As Fired

Air Typical Excess (minimum as a %)

Air Total Air kg/GJ 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

2 1

Analysis by volume

Analysis by volume

CH4

31%

CO

12%

C2H6

20%

H2

42%

C3H8

38%

CH4

37%

H2

5.6%

C2H4 and higher

5%

C4H10 and higher 1.0%

CO2

Remainder

Inert Gases

6

As

Remainder

affected by air infiltration. With heat recovery equipment the readings should be taken immediately downstream of the equipment.

This means that approximately 4 per cent less than the theoretical air required for complete combustion is being supplied to the burners. If the type of process permits it, increasing the combustion air supply should reduce the carbon monoxide.

The flue gas heat loss has four components, which can be calculated separately. • •

Occasionally, CO occurs with high O2. This is usually an indication of poor mixing of the fuel and combustion air. Sometimes improvements can be made by adjusting the burner air dampers to create more turbulence where the fuel and air mix. In other instances it may be necessary to replace the burner assembly.

•

•

Dry gas heat loss. Heat loss from the water vapour 1 contained in the combustion air . Heat loss from the water vapour produced by the combustion of the 2. hydrogen in the fuel Heat loss from the water vapour produced by the evaporation of moisture 3 in the fuel .

For natural gas and oil, the moisture in the fuel is minimal, and the evaporation of the moisture heat loss can be ignored. The values for flue gas losses can be calculated using figures from the appendix, which gives a boiler efficiency test. Figure 4 below shows this graphically for fuel oil.

2.2 HEAT LOSSES • The heat discharged from the stack, is usually the largest loss in a fuel fired boiler or furnace. Flue gas analysis and flue gas temperature can be used to calculate the loss. If there is no heat recovery equipment on the furnace or boiler, these measurements should be taken at the outlet to minimize the possibility of the readings being

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)

7

30 per cent moisture, this fuel heat loss is 5.5 per cent of the fuel heat content. At 60 per cent moisture, the loss increases to 21 per cent.

In practice this loss can vary from 8% to 50% depending on the fuel. The major influencing factors are the exit flue gas temperature and the degree of excess air present.To minimize losses in coal-fired plant, correct combustion is essential including better fuel preparation, better stoking practices and improved control of combustion air – both the undergrate and the overgrate draughts. The same factors apply to oil-fired boilers. Fuel preparation should be correct (uncontaminated and at the right temperature), burners undamaged and properly maintained, and combustion air (both primary and secondary) should be introduced at the right rate and with adequate turbulence.

2.2.1 HEAT LOSS DUE TO INCOMPLETE COMBUSTION Heat can also be ‘lost’ by the incomplete combustion of fuel, this is indicated by the presence of CO and, in the case of coal, combustible material left in the ash.

2.2.1.1 HEAT LOSS TO CO

For fuels such as coal, biomass, and industrial waste or municipal refuse, the heat loss from the moisture in the fuel can be considerable. Wood, for instance, could have a moisture content of up to 60 per cent, depending on the source and capability of the wood burning equipment. Figure 5 shows the variations in the moisture heat loss for a typical biomass fuel having different moisture contents at a flue gas temperature of 200 ºC. At

By controlling the amount of dark smoke produced, the level of CO can be kept to a practical minimum. The three influencing factors are insufficient combustion air, inadequate fuel/air mixing, or the ingress of cold air ‘freezing’ the combustion reaction. The heat loss, which is measured 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)

8

the losses increase very rapidly as the total air is decreased. The measure of this condition is reflected by the presence of significant combustibles in the flue gas.

carbon into carbon dioxide, is relatively small, but the rapid fouling of heat transfer surfaces under these conditions adversely influences the boiler’s performance.

In coal, biomass and other solid fuels, unburned combustible material will be found in the refuse collected in the ash pit and the fly ash hopper.The loss should be determined when the boiler is tested for efficiency.To do so requires a method of collecting and weighing the refuse under controlled conditions and laboratory testing the refuse for its HHV. The loss can be calculated as shown.

2.2.1.2 HEAT LOSS TO COMBUSTIBLES IN THE ASH (COAL APPLIANCES) This loss generally varies from 2% to 5%. It is a clear indication of combustion air starvation for which there are three possible causes: poor air distribution under the grate: too thick a fire bed: or uneven bed thickness resulting from poor stoking practices.

Unburned combustible heat loss = Dry refuse quantity x Refuse heat content Where units are:

The unburned combustibles heat loss is not significant for properly operating oil and gas fired installations, but it can be for solid fuel units. Figure 1 demonstrates that there could be a minor unburned fuel loss at the maximum efficiency point, but the real significance of this figure is that

Heat loss (MJ/kg fuel as-fired) Dry refuse (kg of refuse/kg of as-fired fuel) Refuse heat content (MJ/kg of refuse)

•••••••••

9

3. HEAT TRANSFER

•••••••••••••• 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)] 2 A = Surface area (m ) T = Mean temperature differential 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 heat transfer increases in proportion to surface area, and to temperature differential across the solid, and is inversely proportional to material thickness.

The transfer of heat from the burner flame to the product can be by conduction, convection, or radiation, and in most instances a combination of all three.

3.1 CONDUCTION • Heat transfer to the product by conduction is only significant in indirect heated equipment, where the product is isolated from the flame by a heat exchange surface. Muffle furnaces and furnaces using radiant tube heaters (Figure 6) are examples of indirect heating arrangements. Heat conducted

Figure 6: Radiant Tube Gas-Fired Rotary Furnace. (Source: Canadian Gov.) (Energy Management Series 7. Page 13. Figure 7)

10

2

Example: A muffle furnace has a 10 mm thick, high nickel steel enclosure with a surface area of 55 m . Useful heat to the product, all of which is transmitted through the wall, is 1.9 GJ/h.The thermal conductivity of high nickel steel is 31 W/(m·ºC).The temperature drop through the muffle wall can be determined as follows: Heat Heat Heat Heat

2

Conducted = 31W / (m·ºC) x 55m x DT x 3.6 Conducted = Conducted = 0.01 m 6 conducted is 1.9 GJ/h, or 1.9 x 10 kJ/h

Rearranging the equation, T T T

= = = =

6

1.9 X 10 X 0.01 31 X 55 X 3.6 3.1ºC

The temperature drop across the enclosure is 3.1ºC at the specified rate of heat transfer.

3.2 CONVECTION •

surface increases, but not proportionally. The following equation can be used for gases:

Heat transfer by convection takes place at the boundary between a solid wall and a gas or liquid. Intermingling takes place between the stagnant layer of fluid at the wall and the moving fluid stream next to the stagnant layer. Tests on rate of heat transfer by convection show that the rate is proportional to surface area and temperature differential between the solid and the fluid. It also increases as the velocity of the fluid over the wall

Q

=

0.78

23.46 x A x T x V

xd

Where, Q

= Rate of convection heat transfer (KJ/h) 2 A = Area of heat transfer (m ) T = Temperature differential between solid and fluid (ºC) V = Fluid velocity (m/s) 3 d = Gas density (kg/m )

Example: A furnace is 3 metres long and has a 1 metre by 1 metre cross-section. Flue gas flows through the furnace at an average velocity of 0.5 m/s with a gas temperature of 500ºC.The temperature differential between the furnace walls and the flue gas averages 150ºC. For most practical purposes, the density of air 3 can be used for flue gas. From standard references, the density of air at 500ºC is 0.458 kg/m .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 Q

= =

(1 + 1 + 1 + 1) m x 3m 2 12 m

= =

23.46 x 12m x 150ºC x (0.5m/s) 11 263 kJ/h

2

11

0.78

3

x 0.458kg/m

emissions of the two bodies. The equation for a furnace is:

3.3 RADIATION • Heat transfer by radiation becomes significant for temperatures above 600ºC. A hot body emits radiation in the form of heat, which can be received by another solid body in the path of heat radiation. In an electric furnace or boiler, the walls or tank, which are heated by the electrodes, emit heat radiation to the furnace contents.

[( ) ( )]

K x F x [( T1 – ( T2 ] KxFx K x F x 100 100

Where, Q

=

Rate of radiation heat transfer (kJ/h) “Black body” coefficient (20.6) Overall radiation factor depending on emissivity and surface areas of the furnace walls and contents Absolute temperature of hot and colder bodies respectively (K) A1

= =

T1,T2 =

F F F F F

Emissivity is a measure of the heat radiated from an object compared to that radiated from a similar sized “black body” at the same temperature. The maximum value of emissivity is that of the “black body’; which is 1. Typical emissivity values for furnace walls and oxidized steel are 0.8 to 0.9. Because both the hot body, (the furnace wall) and the cooler body, (the furnace contents) are emitting radiation, the net total heat received by the contents is the difference between the heat

4

= = =

K F

The amount of heat radiated from a solid body is proportional to the fourth power of its absolute temperature, and directly proportional to its emissivity. Absolute temperature is the number of degrees above absolute zero and is measured in Kelvin (K), which is equivalent to degrees Celsius plus 273.

4

Q Q Q

= = = = =

Where, A1

=

A2

=

1

e 2 e

= =

( )( )

1 + ( A1 ) ( 1 – 1) 1 + ( A1 ) ( 1 – 1 e1 + A2 e2 – 1

Surface area of furnace contents exposed to walls 2 (m ) Surface area of furnace walls 2 (m ) Emissivity of furnace contents Emissivity of furnace walls

Example: A furnace with a square cross section of 1 metre by 1 metre is heating carbon steel billets 100mm by 100mm.The furnace wall temperature is 1000ºC.The furnace floor does not radiate heat. From Table 3, the emissivity of a fireclay brick furnace wall is 0.75, and the emissivity of oxidized carbon steel is 0.80.The heat input to the billet per metre of length when the steel is heated to 650ºC can be calculated. A1 A2 F F F F F T1 T2

= = = = = = = = = = = = = =

(0.1 + 0.1 + 0.1) x 1 2 0.3m (1 + 1+1) x 1 2 3m 0.3

( )(

1 + ( 0.3 ) ( 1 – 1) 1 + ( A1 ) ( 1 –1 0.8 + 3 0.75 – 1 0.234 1000ºC + 273 1273K 650ºC + 273 923K

12

)

Heat radiated/metre length Q = K x F x [( 1273 = 20.6 x 0.234 x Q = KxFx 100

4

Radiation also takes place from hot gases to the furnace contents. This method of heat transfer does not follow the same laws as the radiation from solid bodies. Radiation from a luminous flame is higher than from a clear flame of hot gases.

4

[( ) ( )]

=

– (923 ] 100

91 604 kJ/h

••••••••• 4. the fuels

•••••••••••••• furnace maintenance costs are low. Natural gas burners tend to be simpler with fewer mechanical parts and are also therefore cheaper to maintain.

Each conventional fuel differs from the others in its combustion characteristics, and this influences heat transfer. Fuels may be solid, liquid or gaseous, and either ‘commercial’ or ‘waste’. Commercial fuels are fossil fuels, which are extracted, treated/refined to varying degree and sold nationwide by organizations such as oil companies. Waste fuels are by-products or adjuncts of processing or domestic activities and are, obviously, only economically available locally.

Natural gas would normally be the preferred fuel for burning in boiler plant if convenience alone is considered. It does not have to be stored; in common with all the gaseous hydrocarbons it mixes readily with combustion air to burn clearly; and, ideally, the products of combustion are just water and carbon dioxide. These basic arguments would seem to carry a great deal of weight because globally the majority of new boiler and furnace installations in recent years have been gas tired.

Factors other than simple conversion to heat must also be considered, including those relating to: the storage and handling of the fuels, maintenance, environmental impact etc. All of these influence the overall efficiency and true cost of burning a fuel.

The availability of an adequate gas supply at individual sites needs to be checked in advance as local constraints in the distribution system can sometimes lead to delays in providing a connection. A second factor is safety. Complying with legislation regarding the supply and use of gas involves some specialised equipment that has to be maintained.

4.1 PIPELINE GAS • Because gas mixes so readily with air and burns without producing smoke and soot, boiler and

13

operational and maintenance costs. The storage tanks involved are pressure vessels and therefore subject to both annual and long-term inspection and testing. If a customer owns his own tanks he is responsible for carrying out all inspections and tests at his own expense. In practice, many customers lease or rent the tanks from the fuel suppliers, eliminating both this responsibility and also that of general maintenance.

Thirdly, burning gas does cause pollution. While the pollutants do not include smoke or noxious substances, they do include gases that contribute to the so-called greenhouse effect. Gas, being composed predominantly of methane, is in itself one such gas. Carbon dioxide, which is produced by the combustion of all fuels, is another: its production is not only unavoidable but also desirable as its presence indicates complete combustion of the gas. However, pipeline gas also produces oxides of nitrogen (NOx). This is because the gas burns at high temperatures and this provides the additional energy necessary to make the oxygen and nitrogen in the air combine.

The second major difference is that LPG is heavier than air. If natural gas, which is lighter than air, escapes, all sources of ignition should be removed and windows opened: it will then disperse naturally. LPG, on the other hand, may find its way down into pipe ducts, cable tunnels, drains, cellars etc., and will not disperse unless forced to using a fan. This characteristic influences the location of storage tanks in relation to buildings, hollows, drains, cellars etc. and plant location may be affected.

As regards the pricing of gas, the actual price that a customer will pay, as for any fuel, depends on the amount used and the type of supply, and can vary over a wide range. Prices are generally competitive with oil products, for example with gas oil for firm gas supplies and with heavy fuel oil for interruptible supplies. Continued plant operation during interruptions of an interruptible supply requires a boiler to be dual-fuel fired usually with oil as an alternative. In firing these two fuels the burner would normally be set to achieve the most effective results on gas, because gas is used for most of the year, with oil firing only on the few days of interruption sometimes experienced.

4.3 FUEL OIL • Crude oil is a complex mixture of hydrocarbons. The other fuel users mainly require the lighter fuels – petrol, kerosene, diesel, oil, gas oil etc. This ‘end of the barrel’ also provides the main feedstock requirement for the petrochemicals and plastics industries. However, the primary separation of oil provides mainly the heavier more viscous fuel oils, which potentially cause problems in storage, handling, combustion and environmental pollution.The main advance of fuel oil, on the other hand, derives from the fact that these heavier fractions tend to be cheaper.

4.2 LIQUID PETROLEUM GAS • Liquid Petroleum Gas (LPG) is used to describe two fuels: propane and butane. In practice the vast majority of installations use propane. All the general comments about natural gas apply equally to LPG.

Problems relating to fuel oil storage include both the capital cost of the storage tanks and the problem of handling the oil. Fuel oils are viscous liquids, which become thicker and more intransigent the colder they become. Gas oil, the lightest and least viscous of the fuels, will usually remain in liquid form no matter how cold the

One major difference between the two fuels is that LPG requires both storage facilities and the special precautions needed in relation to leakages. The first can be very significant in terms of both the capital cost of a project and its overall

14

efficiency. The uncontrolled overheating of oil can be very expensive, and uninsulated or poorly insulated tanks or pipes are also a major waster of energy.

winter. This either allows it to flow under gravity from the tank to the burner or enables it to be easily pumped. This holds true unless prolonged periods of cold weather occur where the temperature remains below freezing for a week or more. Under these conditions, some of the waxes contained in the oil begin to alter into sticky solids. Typically, these solids build up on the filters in the burner supply line, eventually blocking them. Although this is an infrequent occurrence, some exposed sites have installed electric trace heating on the filters and/or the external distribution pipework as a precaution.

Considerable energy is wasted if all the oil in a tank is heated to the required pumping temperature, and it is also bad practice to have too much hot oil circulating and not being used by the burners. A well designed hot oil ring main circulates sufficient oil plus about 10% in order to meet the maximum demand for all the burners it serves. Fresh oil is drawn from the storage tank as required, but the storage tank never forms part of the basic circulation system thereby allowing all the oil to heat up to the pumping temperature. This ensures that both the size and the capital and running costs of the oil heaters are kept to a practical minimum.

The heavier grades of oil require heating in order to remove them from the tank at all.To reduce the amount of energy required for pumping the oil to the burners, an appropriate pumping temperature should be maintained.

The penalty of this oil heating requirement is that it is uneconomic to use these heavier grades of fuel oil on small boiler plant. Below 3 MW heavy oil would be inefficient and, for bunker oil, 20 MW is probably the lower limit. However, the market price for the heavier fuel oils over recent years has encouraged their greater use.

Table 2 shows the recommended minimum storage temperatures for the different grades of oil and also the minimum temperatures for optimising pumping costs.The temperatures given in this table, especially for the heaviest oils are only meant as an indication. With the exception of gas oil, the general trend is for the heavier and more viscous oil grades to require higher storage and pumping temperatures.

Provided that a grade of fuel oil is delivered to the burner in good condition and at the correct temperature for the burner, the production of smoke or carbon monoxide should be minimal.

The oil is heated either electrically or by taking steam from the boiler, thereby reducing its overall

Table 2: Recommended Minimum Storage Temperatures for Different Grades of Oil

Fuel Oil Type

Grade *

Viscosity *Cst @ 100ºC

Minimum Storage Temperature ºC

Typical Pumping 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.

15

The fact that all fuel oils contain some sulphur means that sulphur oxides (SOx) are produced during combustion. Such gases are now considered to contribute to the global pollution problem. Oil, however, burns at a lower temperature than the gaseous fuels and therefore produces less NOx gases.

furnace plant itself, the capital cost incurred includes bunkerage, coal handling equipment, and facilities for ash removal, handling and storage. Operational costs are high because, despite considerable development efforts by plant manufacturers to reduce the labour component, it is rare that coal fired plants are ever fully automated and unmanned.

4.4 COAL •

Maintenance costs are also significantly higher than for the other fossil fuel. The difficulty of achieving clean combustion means that the boilers require more frequent cleaning. Both the fuel and the ash are very hard and abrasive so levels of wear and tear on coal and ash handling equipment are high.

The clean burning of solid fuels presents a problem because the air required for combustion is less readily available to the mass of fuel, compared with atomised liquid fuels and gas. As a result, coal burning has been responsible for most of the traditional forms of air pollution – smoke, soot, grit and dust. Modern coal plant using microprocessor control, on boilers with improved stoker design, has eliminated this problem. Stringent control of SOx and particulates can be achieved through the use of limestone injection, cyclones and bag filters.

The disposal of ash in a manner that avoids pollution is a significant operational component and, in some regions of the country, can be a costly business. Low combustion temperatures limit pollution from NOx, but the SOx released by coal combustion must be considered. Both the calorific value and the sulphur content of coal vary from source to source. The average South African coal sold into the industrial market has low sulphur content and is less polluting than the heavier fuel oils.

Throughout the sub-tropical and temperate regions of the world coal deposits are generally significantly larger than crude oil or natural gas deposits. As crude oil prices have risen, many oilimporting countries with significant coal deposits have undertaken considerable research into coal burning and, in some cases, have implemented policy decisions promoting the use of coal for boiler firing.

4.5 CHOICE OF FUEL • The choice of fuel is not a simple matter. It involves balancing a number of factors including the capital cost of the plant, the price of the fuel, and operating and maintenance costs. Some consideration should also be given to likely future changes in fuel and pricing policies and to pollution control legislation.

Coal is the cheapest of the available conventional fuels. Furthermore, coal prices tend to be more stable than prices for other fuels, and long-term price contracts with only moderate built-in increases are available. A coal-fired plant does, however, incur higher capital and operating costs. As well as the boiler or

16

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 summarises those advantages and disadvantages that can be estimated and quantified for each fuel.

Capital Cost For:

NATURAL GAS Disadvantages

Advantages

FUEL OIL Disadvantages

Advantages

COAL Disadvantages

Advantages

Advantages

Table 5:The pros and cons of various fuels. LPG Disadvantages

Capital Cost For:

Capital Cost For:

Tanks

Storage Tank (or leased)

Bunkerage Insulation Fuel Handling Heavy Fuel Oil Ash Handling Running Cost For: Tank Heating

Running Cost For: Fuel (Especially for Small Installations)

Running Cost For: Fuel Cost

Boiler Cleaning Environmental Costs:

Boiler/Furnace Cleaning Burners Environmental Costs:

Interrupt Tariff Heavy Oil as Second Fuel Maintanance Costs For: Safety Equipment

Environmental Costs:

Smoke Emission

No Sulphur

Wear from Abrasive Fuel & Ash

Maintenance Costs For:

No Storage No Sulphur

Maintenance Costs For:

Cheaper Than Gas

Low Cost

Heavy Fuel Oil

Maintenance Costs For: Safety Equipment

Environmental Cost:

High NOx Smoke Emission

High NOx

Grit & Dust Emission Sulphur Emission Sulphur Emission Clean up

Heavy Fuel Oil

Ash Disposal Cost

Higher NOx

17

5. combustion equipment: oil and gas burners

••••••••• Many boilers are equipped with combination natural gas and oil burners with the second fuel used as back up for the prime fuel.

In order to ensure the proper mixing of fuels with combustion air and the correct flame shape, for maximum heat transfer from the flame to the water/steam or heated product, specialized equipment is used. The type of equipment is dependent on the furnace/boiler conditions and the fuel or fuels of choice. (Boilers and furnaces can be set up to fire more than one fuel.)

5.2 OIL BURNERS • Oil burners are more complicated because the fuel has to be in the right condition for clean and rapid combustion. This entails atomising the oil into small droplets of the correct size, which can only be done if the oil is at the right temperature and therefore the right viscosity. At too low a temperature the droplets are too big: combustion is poor and produces soot and smoke. At too high a temperature the droplets can be too small, passing through the flame too rapidly to burn. In neither case is the full energy content of the fuel being used: furthermore, the heat transfer surfaces become fouled.

5.1 GAS BURNERS • Apart from the safety requirements in their design, gas burners are essentially simple. Very small boilers use a simple atmospheric burner, which entrains its combustion air from its surroundings. However, as the air and gas are not forced to mix, surplus air is required to ensure complete combustion. This surplus is heated and then passes out via the flue, thereby reducing boiler efficiency.

Oil burners are of three basic types. The simplest and most widely used is the pressure jet where the oil is pumped at pressure through a nozzle. The air or steam blast type uses gas pressure to shatter the oil into droplets, while the Rotary Cup uses centrifugal force to break the oil up. Each type of burner has its benefits and disadvantages.

A larger boiler with a fully enclosed combustion chamber needs a burner that will force the air and gas to mix thereby controlling the length and shape of the flame.The quantity of combustion air can be precisely controlled to maximise combustion efficiency.

5.2.1 PRESSURE JET

Natural gas mixes readily with air.The ring-type gas burner consists of a circular barrel ringed with multiple outlet ports. The “spud” type burner consists of a ring of 4 to 8 single barrels, each with a widened end containing multiple outlet ports. In either case the register surrounds the barrels with air.

Advantages: • Very simple in construction and cheap to replace. • Comes in many sizes to suit most applications.

18

•

country have to meet statutory safety and emission standards.

Can produce all flame shapes from ‘long and thin’ to ‘short and fat’ so can fit all types of boiler or furnace combustion chamber.

5.2.4 LOW EXCESS AIR BURNERS

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 required for atomisation.

Standard natural gas and oil burners operate at 10 to 15 per cent excess air at full capacity and higher excess values at lower firing rates. The increasing excess air with decreasing firing rate phenomenon results from burner registers, which are fixed at settings that provide best results at full capacity. Low excess air burners permit operation at 2 to 5 per cent excess air. A reduction of excess air from 15 to 5 per cent would reduce fuel costs by almost 1 per cent.These savings result from higher cost features as follows:

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.

Better design of the air diffusers, air register, and burner, which achieve better mixing and combustion. Burner registers which are modulated with the tiring rate to provide better combustion at firing rates below 100 per cent.

5.3 BURNER CONTROLS • In conjunction with the choice of burner type, consideration must be given to the control system required. The simplest ON/OFF control means either that the burner is firing at full rate or that it is off.The major disadvantage with this method of control is that the boiler is subject to large and often frequent thermal shocks every time the boiler tires. Its use is therefore limited to small boilers with an output up to 300 kW.

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.

Slightly more complex is the HIGH/LOW/OFF system where the burner has two firing rates.The burner operates first at the lower tiring rate and then switches to full firing as needed, thereby overcoming the worst of the thermal shock. The

Oil and gas burners produced or sold in this

19

In matching a burner and a control system to a boiler three factors must be taken into consideration.

burner can also revert to the low-fire position at reduced loads, again limiting thermal stresses within the boiler. Typically this type of system is fitted to boilers with an output of up to 3.5 MW.

• • •

A modulating burner control will alter the firing rate to match the boiler load over the whole turndown ratio. Every time a burner shuts down and restarts, the system must be purged by blowing cold air through the boiler passages: this wastes energy and reduces efficiency. Full modulation, however, means that the boiler keeps firing, and fuel and air are carefully matched over the whole firing range to maximise thermal efficiency and minimise thermal stresses.Typically this type of control can be fitted to boilers above 1 MW.

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 suitable for heavy fuel oil The basic choices as they relate to oil burners are summarised in Figure 7. There is always some overlap between burner types and control system types 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.)

20

6. combustion equipment: solid fuel combustion

••••••••• Stokers are classified according to the manner in which the fuel reaches the fuel bed. In an underfed stoker, the fuel and air enter the burning zone from beneath the bed. Overfed stokers have the fuel entering the combustion zone from above, in the opposite direction to the airflow. The spreader-type overfeed stoker delivers fuel so that a portion burns in suspension while the remainder falls and burns on the moving grate.

Because carbon burns fairly slowly and coal needs to be in the combustion chamber for a relatively long period for the air to reach it and cause complete combustion, many forms of stoker (for transferring coal to the grate) have been developed. Some have experienced periods of popularity and have now declined, while others have stood the test of time. Coals from different pits or washeries can have very different combustion properties. Furthermore, coals from the same pit that have been stocked for long periods are very different from newly mined coal. As a result a boiler combustion system must be regularly adjusted to maximise energy conversion. In the following section only those types of stoker that would be fitted to a boiler with an output of 1.5 MW and above are considered. Below this level there is limited choice: each boiler comes with its own proprietary form of stoker, screw feeding the coal either onto the top of the fire or pushing it up from below.

6.2 CHAIN GRATE STOKER •

The chain grate stoker has for many years been the most widely used method for firing coal on medium sized industrial and commercial boilers, even though it is relatively expensive to buy, operate and maintain. To reduce operating costs equipment manufacturers are working to develop a fully automatic system requiring little or no intervention from trained operators. The coal is fed onto one end of a moving steel belt. As the belt moves along the length of the furnace, the coal burns before dropping off the end as ash. Some degree of skill is required, particularly when setting up the grate, air dampers and baffles, to ensure clean combustion leaving the minimum of unburnt carbon in the ash and to achieve maximum heat transfer in the furnace chamber.

Three basic types of stoking system are commonly used with the larger boilers - two of them traditional designs and one a relatively modern development.

6.1 STOKERS •

This type of stoker will only operate effectively using certain types and qualities of coal. Coal must be uniform in size, as large lumps will not burn out completely by the time they reach the cod of the grate. Furthermore, small pieces or ‘fines’ may block the air passages in the grate and make it

Stokers are mechanical devices that burn solid fuel in a bed at the bottom of a combustion chamber. They are designed to permit continuous or intermittent fuel feed, fuel ignition, adequate supply of combustion air, release of gaseous products, and disposal of ash.

21

de-ashed by hand. Effort has been put into developing an automatic de-ashing system but, obviously, this has considerably eroded the sprinkler stoker’s price advantage.

more difficult for combustion air to reach the coal. The grate also relies on having a layer of ash on top of it to protect it from the highest temperatures of the burning coal, so using coals with a very low ash content will result in rapid grate damage.

Like the chain grate stoker, this type of stoker is selective with regard to fuel size. ‘Fines’ in the coal are picked up by the combustion air and flue gases and carried through the boiler. This can cause considerable erosion within the boiler and result in high grit emissions from the stack.

6.3 SPRINKLER STOKER • The sprinkler stoker is an original mechanical stoker system, which has been brought up to date. The principle is to spread fresh coal on top of an already, burning firebed. Once the system has been set up to spread this coal evenly it is simple to operate and has many fewer mechanical parts to maintain than the chain grate stoker.

6.4 FLUIDISED BED COMBUSTION • Fluidised bed combustion is the most recent coalburning technology, the fuel being fed onto a hot, air-agitated bed of refractory sand.This system has two main advantages:

Many units of this type have been manufactured with control systems very similar to those for gas or oil-fired boilers. Fuel feed rate and combustion air are adjusted in parallel to give a turndown ratio of 3:1.The chain crate stoker can also achieve this but the sprinkler can be regulated much more quickly.

1. It is much less selective in terms of fuel quality and can burn not only very poor coal with a high ash content but even industrial or commercial waste. 2. The lower combustion temperature involved allows cheaper materials and refractories to be used in its construction.

This type of stoker was popular initially because it was very much cheaper than the chain grate equivalent. Its main drawback was that it had to be

However, this technology is still new and is in the experimental stage in South Africa.

•••••••••

22

7. energy saving equipment

•••••••••••••• A short description of common equipment used for saving energy in boilers and furnaces follow. In some cases these are discussed further under the energy savings sections of either boilers or furnaces.

LMTD =

Logarithmic mean temperature difference (ºC) 3.6 = Conversion factor from watts to kilojoules per hour LMTD = T1 – T2 LMTD = LMTD = T1 LMTD = Ln LMTD = T2 Where, LMTD = Log mean temperature difference (ºC) T1 = Greater temperature difference between the flue gas and the heated air or water (ºC) T2 = Lesser temperature difference between the flue gas and the air or water (ºC) “Ln” is the natural logarithm

( )

7.1 FLUE GAS HEAT EXCHANGERS • Since most of the heat losses from a fuel fired furnace appear as heat in the flue gas, the recovery of this heat can result in substantial energy savings. A common method is to install a heat exchanger at the furnace exit.

A heat exchanger can be used to transfer heat from the hot flue gas to the incoming combustion air, or to the heat water used elsewhere in the plant. The rate of heat transfer is proportional to the surface area of the heat exchanger, and to the mean temperature differential between the flue gas and the combustion air.

Q

=

U x A x LMTD x 3.6

Where, Q U

= =

A

=

Rate of heat transfer (kJ/h) Heat transfer coefficient of 2 heat exchanger [W/(m ·ºC)] Surface area of heat ex2 changer (m )

A heat exchanger may be used to heat water with the heat from flue gases. An important design consideration is how close the heated water temperature should be to the temperature of the hot gas entering the exchanger. It is not possible to heat the fluid to a temperature above the temperature of the hot gas entering, regardless of the relative fluid and hot gas flows. Small temperature differentials imply large heat exchanger surfaces. This is illustrated by the following example.

23

Figure 8:Tempering Air Heat Exchanger. (Source: Canadian Gov.) (Energy Management Series 7. Page 18. Figure 11.)

Example of savings 3

A heat exchanger is to be added to a dryer which is exhausting 450 000 m /h of moist air at 100ºC.The 3 exhausted air is used to heat up 350 000 m /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 heat 2 transfer coefficient quoted by the manufacturer of 28 W/(m ·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 exchanger 3 of this type. Density of air at standard conditions is 1.204 kg/m , 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 3 3 350 000 m /h x 1.204 kg/m x 1.006 kJ/(kg·ºC) x (85-10)ºC. 6 31.79 x 10 kJ/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 10

6

=

Rearranging the equation: (100ºC - Tout) = (100ºC - Tout) = (100ºC - Tout) = =

450 000 x 1.204 x 1.006 x (100ºC – Tout) kJ/h 31.79 x 10

6

450 000 x 1.204 x 1.006 58.3ºC

24

Heat exchanger exhaust temperature,Tout Maximum temperature differential, T1

= = = =

Minimum temperature differential, T2

100ºC – 58.3ºC = 41.7ºC 41.7ºC – 10ºC 31.7ºC 100ºC – 85ºC = 15ºC

The logarithmic temperature difference (LMTD) is:

Cold air heat gain (Q) Surface area, A Surface area, A Surface area, A

LMTD LMTD LMTD LMTD LMTD

= = = = = =

31.7˚ C – 15˚ C

= = = = =

31.79 x 10 kJ/h = 28 W/(m ·ºC) x A x 22.3ºC x 3.6 kJ/Wh 6 31.79 x 10

In

(

31.7˚ C

15˚ C 22.3ºC

)

6

2

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 heat exchanger required in increased considerably.The calculations are as follows: Temperature of heated air

= =

100ºC – 5ºC 95ºC

Cold air heat gain

= =

350 000 m /h x 1.204 kg.m x 1.006 kJ/(kg·ºC) x (95 – 10)ºC 6 36.03 X 10 kJ/h 6 36.03 x 10

(100ºC – Tout) (100ºC – Tout) (100ºC – Tout)

=

Tout

= = = = = =

T1 T2 LMTD LMTD LMTD LMTD LMTD

= = =

= = = =

=

= =

450 000 x 1.204 x 1.006 66.1ºC 100ºC – 66.1ºC 33.9ºC 33.9ºC – 10ºC 23.9ºC 100ºC – 95ºC 5ºC 23.9˚ C – 5˚ C In

= Surface Area (A) Surface Area (A) Surface Area (A)

3

= =

( ) 23.9˚ C

5˚ C 12.1ºC 6 36.03 x 10

28 x 12.1 x 3.6 2 29 541 m

25

3

It should be noted that the reduction in the temperature differential to 5ºC would require the heat exchanger area to be slightly more than doubled. An increase in design temperature rise of the incoming air 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 is important.

liquid heat exchanger - or economizer - used to heat boiler feed water.

7.1.1 ECONOMISER (FEEDWATER HEATER) This is applicable mostly to boilers, and is an option used for heating incoming boiler water by cooling the flue gases. The equipment is a gasliquid heat exchanger. Care must be taken not to allow the flue gases to cool below the sulphur dew point. Economizers can be considered where hot water is required. For furnaces, if the use of hot water and the operation of the furnace do not always occur simultaneously, it may be practical to install an insulated hot water storage tank. This would level out the effect of variations in the hot water supply and demand.

7.2 ACCUMULATORS • Boilers produce steam to meet demand. When spikes in this demand occur, or the load is uneven, it is often the case that an extra boiler would have to be used intermittently, or output of several boilers would rise to meet this demand. In the first case this can be inefficient due to losses associated with the heating and cooling of the boiler shell. In both cases, some of the required boiler capacity (and running and capital outlay) could have been avoided by using an accumulator. An accumulator effectively ‘stores’ or ‘accumulates’ steam from boilers during times of low demand and then can release it during short high demand intervals.

7.1.2 RECUPERATOR (AIR HEATER) In a recuperator air entering the combustion chamber is preheated using the heat of the hot exhaust flue. This is an important measure for furnaces where preheating the feed with flue gases is more difficult that for boilers.The hot gas passes inside tubes arranged in bundles. The combustion air is directed over the outside of the tubes by means of a series of baffle plates. Combustion air pre-heat has always been regarded as the poor cousin of the economizer for boilers because air pre-heaters are large and less efficient than a gas-

7.3 INSULATION • Insulation is used to retain heat within the furnace or boiler enclosure. Common insulation materials include calcium silicate, mineral fibre, ceramic fibre, cements, cellular glass and glass fibre. An indication of the heat loss from the hot walls of a furnace or boiler is given in figure 9.

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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.)

CO2 monitoring equipment used by a well trained and intelligent boiler operator is still the best method of limiting excess air and hence increasing efficiency.

A significant development in this field, for furnaces, has been the use of ceramic fibre insulation, which is a better insulator than solid refractory material and also requires less heat to reach the operating temperature. The disadvantages are higher initial cost and low resistance to physical damage. A layer of refractory on the bottom of the furnace and other areas subject to damage is normally used to protect the ceramic fibre. Further layers of ceramic fibre insulation can be installed on the outside of the refractory as required.

The production of the ‘zirconium cell’ for O2 detection has made available a reliable measuring system, and this has resulted in the development of various systems, which automatically control the amount of excess air, thereby overcoming variations in the fuel and air parameters. Using these oxygen detection feedback controllers, usually termed oxygen trim control, allows much lower excess air levels to be achieved throughout the operating range.

7.4 O2 ANALYSERS •

The simplest systems use the feedback signal to adjust the combustion air damper via a secondary (‘tory’) linkage. The most sophisticated systems feed directly back to a microprocessor unit, which sets the combustion air/fuel ratio.

Systems for checking the O2 or CO2 content of a boiler flue gas have been available for a long time but, historically, none have been sufficiently reliable to be incorporated in an automatic control strategy. Portable or permanently installed O2 or

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In the past the main problems encountered included designing dampers that were virtually gas tight, and incorporating a control system that would prevent the boiler firing against a closed damper. Today, automatic gas-tight shut-off dampers for installation in a boiler exit flue are widely available. In the case of forced draught (FD) oil and gas burners a cheaper alternative is available, particularly for retrofit situations: this involves the installation of an automatic damper at the combustion air fan inlet.

7.5 VARIABLE SPEED FAN DRIVES • Popular in Europe and Japan are variable speed drives for motors.They are used in this context, to drive combustion air fans. By varying their speed (together with electrical input) to match air required electrical energy can be saved during periods of partial load. Conventionally the airflow is limited via dampers, while the motor runs at a fixed speed. At low loads this can lead to a disproportionately high electricity demand. Variable speed drives are economically less attractive in South Africa due to relatively low electricity charges.

7.7 WASTE HEAT BOILERS • Waste heat boilers use hot flue gas to produce steam. In most instances there is a common steam header into which the waste heat and fuel fired boilers are connected. The fuel fired boilers will then supply the difference between the steam demand and the steam supplied by the waste heat boiler.

7.6 FLUE GAS DAMPERS • For situations where boilers or furnaces are regularly shut down because of changes in load, the heat loss caused by the chimney effect drawing cold air through the boiler can be significant.This is particularly true when a number of units are connected to a common header and are operated in a cascade manner.

Economizers are often used with waste boilers to preheat the feedwater to the boiler. The hot flue gas passes through the boiler before going to the economizer.

•••••••••

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8. POLLUTION

•••••••••••••• conventional fuel. Again, it could to some extent be removed either by wet scrubbing or by absorption. The current emphasis is on improving overall combustion efficiency so that less fuel is burned: this, in turn, reduces the production of CO2.

Sulphur compounds produced by combustion, escape into the atmosphere and have various effects. These include the production of acid rain and ambient pollution that is hazardous to human health. It has also been postulated that other products of combustion, such as CO2 are causing global problems, and this has led to an emphasis on ‘Green’ policies in many countries.

Particulate emissions are considered to be the most ‘dangerous’ in the South African context. Ambient particulate levels are high and believed to be the most significant cause to poor respiratory health among South Africans. While some particulates are emitted into the atmosphere others are caught in pollution control equipment or (especially with larger particles) in the combustion equipment. This has to be responsibly managed.

Combustion products which are widely report to be damaging to the atmospheric environment are particulate emission, sulphur compounds (SOx), nitrogen oxides (NOX), carbon dioxide (CO2), methane (CH4) and nitrogen compounds (NOx). Although a process for producing low sulphur fuel oils has been in existence for many years, it is expensive: it adds to the cost of a litre of oil and leaves sulphur residues which have to be disposed of without causing alternative forms of pollution. Limestone, when burned with coal will, however, trap 80% or more of the sulphur released by the fuel. The sulphur content of natural gas is very small and nearly all of that is deliberately added as the stenching agent (so that the gas can be detected).

The production of NOx can be restricted by correct design of the combustion systems. The most significant problem occurs with those fuels having the highest flame temperatures, i.e. fuel oil and gas. However in the case of coal a significant contributor to nitrogen oxide formation is the nitrogen content of the fuel, which is generally higher than in oils and gas. A great deal of research has gone into developing low excess air burners, which have been shown to limit NOx production.

There are basically two systems for removing sulphur from flue gases: the wet scrubbing method which washes the SOx out using water: and the dry method of adsorbing the SOx onto limestone type compounds. The wet process produces a dirty acid that has to be disposed of without causing pollution, and the dry method produces quite large volumes of spent absorber, which, again, must be disposed of safely.

Plant manufacturers are being compelled to incorporate these new standards into their designs. However, it is not enough for a boiler operator merely to have bought plant, which meets the new standards: he will have to demonstrate that it achieves those standards in day-to-day operation. It is also recognized that ash and grit from coal-

CO2 is inevitably formed as a result of burning any

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vortex separator.Their use is now limited to small stoker-fired units because of their low collection efficiency of very small particles.

fired equipment contain undesirable substances such as heavy metals etc. These also offer the potential for environment pollution, and their disposal and dumping will similarly be subject to greater control in the future. •

Electrostatic filters precipitators electrically charge suspended particles in the gas and then attract them to collecting plates with an electric field. The collecting plates are then trapped to cause the particles to drop into hoppers. Precipitators can be designed for a high collecting efficiency of 98 per cent or more.

•

Fabric filters, or baghouses, have a long history of applications in dry and wet filtration processes to recover chemicals or control stack emissions.The dirty gas is passed through fabric filters with the particulate matter forming a cake on the fabric.The deposit is periodically removed from the filter by mechanically shaking the fabric, or by a pulse of air. Fabric filters can be designed for collecting 99 per cent of particulates or more.

•

Lime or limestone scrubbing is the oldest method of removing sulphur dioxide from flue gas. The boiler flue gas enters a Venturi scrubber and contacts the injected absorbent lime slurry.The flue gas then passes through a vertical spray tower where the slurry and absorbed sulphur compounds are washed out of the gas.

8.1 ENVIRONMENTAL EQUIPMENT • 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 slag that fall into the ‘ash pit’ under the combustion chamber. Fly ash is the fine ash that is carried with the flue gas and deposits in the hoppers beneath the economizer air heater dust collector and precipitator. The conveying of this ash can be achieved mechanically, or by mixing the ash with air or water and blowing or pumping the mixture. Electrical energy is expended on drives for conveyors pumps, compressors or blowers and care should be taken in the operation and maintenance to ensure that system energy is minimized.

8.1.2 AIR POLLUTION CONTROL EQUIPMENT These systems are designed to reduce fly ash (particulates), sulphur oxide and nitrous oxide emissions from the boiler plant. This equipment is not usually required on small boilers firing natural gas or oil. •

All items of pollution control equipment use varying amounts of electrical energy that significantly increase the energy used per plant output. It is imperative that operation and maintenance staff keep this equipment in first-rate working order.

Mechanical cyclone collectors (dust collectors) remove particulates by centrifugal and gravitation forces developed in a

••••••••• 30

9. BOILERS

•••••••••••••• Although different types of boiler appear to vary considerably in their construction, all boilers consist basically of a furnace chamber in which heat is transferred directly from the flame by radiation, and flue gas passages where the heat is primarily transferred by convection to water being heated. Two-thirds of the heat transfer to the water takes place in the furnace and the remaining third in the flue gas passages. Heat not transferred is lost in various forms.

The boilers considered in this guide are limited to those that produce either steam or hot water from the combustion of a fuel. While electrode boilers are used for generating steam from electricity, they are not considered here. The majority of energy savings measures described below are limited only to combustion processes and are not applicable to electrode boilers. The exceptions to this include issues relating to blowdown and insulation. These concepts may be applied to saving energy in electrode boilers with minor adjustments.

There are two fundamental types of boiler: the water tube type where the water is contained in pipes and the hot combustion gases pass around them; and the shell or fire tube type where the opposite is true. All other boilers are derivatives of these two types and have been designed to meet either differing size or dimensional limitations, or differing operational requirements.

9.1. TYPES OF BOILERS • There are various types of boilers that have different configurations and run on various fuels. The configurations are described below.

The boilers described below include: If operated correctly, all types of modern boiler are more or less equally efficient at converting fuel into steam or hot water. Table 1 indicates the expected thermal efficiencies obtainable for different boiler types, based on the gross calorific value of the fuel.

• • • • •

water tube boilers, multi-tubular shell boilers, reverse flame or thimble boilers, steam generators, sectional boilers,

Table 6: Boiler Efficiency According to Boiler Type

Boiler Type Condensing Gas High Efficiency Modular Shell Boiler – Hot Water Shell Boiler – Steam Reverse Flame Cast Iron Sectional Steam Generator Water Tube with Economiser

Efficiency % 88-92 80-82 78-80 75-77 72-75 68-71 75-78 75-78

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• • •

MJ/h, which covers the normal size range of most boilers. For solid fuels, the boilers are site erected, as the large size of the combustion chamber and fuel-firing equipment does not make shipment possible.

condensing boilers, modular boilers and composite boilers.

9.1.1 WATER TUBE BOILERS

The water to be heated is carried inside banks of steel tubes, with the hot gas on the outside of the tubes. The most common boilers consist of a drum connected by vertical tubes (downcomers) to a lower drum or header(s). The downcomers can be heated or unheated. A further set of tubes (risers) connects the two drums and forms the walls of the combustion chamber (Figure 10). Natural circulation begins when the heat supplied to the risers exceeds that supplied to the downcomers, thereby producing a mix of steam and water in the risers of less density than that of the water in the downcomers.

Water tube boilers tend nowadays to be considered only for large steam outputs, which often require superheated steam. For most industrial and commercial applications, however, a multi-tubular shell boiler is more appropriate. Only if the requirement is for an industrial output above 20 MW and/or at pressures above 24 bar or steam temperatures above 340ºC is it necessary to use a water tube boiler. The reason for this is that water tube boilers cost more to build for a given steam output than do multi-tubular shell boilers. The shell boiler can be entirely factory fabricated, mounted on a skid with all its associated equipment (such as feedwater pump. burner. and control panel), and then delivered direct to site. The output and pressure limits for the shell boiler are, however, determined by the feasibility of transporting the completed unit from the fabrication plant to the site.

The traditional water tube boiler relies on water circulation occurring as a result of the thermalsiphon effect: the hot water to the boiler is lighter and rises, drawing in colder water at the bottom to replace it. A variation that allows for a more compact design using smaller diameter tubes is the forced circulation boiler, where the feedwater is pumped through the water tubes. Hot water boilers are similar in appearance and operation to steam units. The circulation of water through the tubes is achieved by pumping.

The output from water tube units starts at about 8.5 MW and rises to power-station-sized units rated at 2000 MW and above. At the bottom of the range, units can be manufactured and delivered to the site in one piece.The larger units are manufactured in sections and delivered for site erection. A typical schematic of an industrial water tube boiler is shown in Figure 10.

Water tube boilers are not often used for hot water production. If they are used for this purpose, it is usually as a ‘Lamont’ boiler.The major potential problem with this type of boiler occurs whenever a power failure stops the circulation pumps, especially in the case of coal fired plant, steam is generated within the tubes and this can lead to overheating of the metal, softening and subsequent tube failure unless the fire can rapidly be drawn and cooling air can be provided at the convective tube bank. This type of plant cannot therefore be used in a fully automated, unmanned boiler house.

9.9.1.1 PACKAGED WATER TUBE BOILERS Natural gas or oil fired units are usually delivered as factory assembled “packaged” boilers. Packaged boilers range in size from about 1500 to l90 000

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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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As materials and manufacturing processes improved, thinner metal came to be used for the tubes allowing more tubes to be accommodated. At this stage in its development the basic boiler was rather long and thin and required a large boiler house area. By making the hot gases go backwards and forwards through a series of tubes, the boilers were designed to be shorter and fatter, and heat transfer rates were improved. The modern multi-tubular packaged boiler is the logical conclusion to this evolutionary process. The packaged boiler is so called because it comes as a complete package. Once delivered to site it requires only the steam, water pipework, fuel supply and electrical connections to be made for it to become operational.

One of the main advantages of the water tube boiler in the 10-20 MW range, where it is in direct competition with the shell boiler, is its ability to react rapidly to load changes.The water tube unit contains only a fraction of the water in a shell boiler so the thermal inertia of the system is much smaller. Water tube boilers can be tired using any individual conventional fuel or they can operate as multi-fuel units. All watertube boilers are capable of operating continuously at any load, from about 15 to 100 per cent of the rated capacity.The highest thermal efficiency normally occurs at about 85 per cent of rated capacity, with efficiencies falling more significantly at loads lower than 60 per cent. The small internal water capacity permits quick response to sudden steam demand changes, and frequent start-up and shutdown operation.

These boilers are classified by the number of passes - the number of times the hot combustion gases pass through the boiler. The combustion chamber is taken as the first pass after which there may be one two or three sets of fire-tubes. The most common boiler is, a three-pass unit as shown in Figure 12 with two sets of fire-tubes and the exhaust gases exiting through the rear of the boiler. Older two-pass units transfer heat less efficiently, fewer fire-tubes giving a smaller heat transfer and the flue gases still containing considerable heat when they leave the boiler. Many such units have had equipment fitted to recover some of this potentially lost heat into the boiler feedwater.

The best energy utilization of a watertube boiler results from steady demand at 85 per cent of rated capacity with the avoidance of sudden swings in demand or frequent shutdowns.

9.1.2 MULTI-TUBULAR SHELL BOILERS These are essentially shell and tube heat exchangers where the combustion gas passes through tubes immersed in water. Firetube boilers usually burn natural gas or oil, although some, with a firebox type of combustion chamber, can be installed on top of a coal or wood burning stoker. They can generate dry saturated steam or hot water up to a maximum pressure of 1700 kPa (gage). The output ranges from 350 to 28 000 MJ/h. The boilers are shop assembled and delivered with integral burner, forced draft fan, and controls.

Four-pass units are potentially the most thermally efficient but fuel type and operating conditions may prevent their use. When this type of unit is fired with heavy fuel oil or coal at reduced output, the heat transfer can be too good. As a result the exit flue gas temperature can fall too low causing corrosion of the flues and chimney and possibly of the boiler itself. The four-pass boiler unit is also subject to high thermal stresses especially if large load swings occur suddenly: these can lead to stress cracks or failures within the boiler structure.

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Figure 12: Schematic of multi-tubular three-pass boiler. (Source: ETSU) (Good Practice Guide 30. Page 51. figure 30.)

Another classification is related to the chamber at the end of the combustion chamber before the hot gases enter the fire-tubes. If this chamber is entirely contained within the water shell it is classified as a ‘wet-back’ boiler, and if the chamber is refractory mounted on the outer plating of the boiler the boiler is classified as a ‘dry-back’ unit.The wetback configuration reduces the number of firetubes and hence, marginally, the boiler size by increasing the heat transfer area at the point where the flue gases are hottest. Multi-tubular shell boilers are available which will fire any of the conventional fuels or any form of industrial or commercial waste.

a coal stoking system but also from the very different flame temperatures and combustion characteristics of the various fuels. Older units were also separately designed for gas and oil firing, again because of the combustion characteristics of the two fuels. Many of the older oil-fired units had to be de-rated when converted to gas firing: without this de-rating the temperature of the flue gases entering the first pass of tire-tubes was found to be too high, causing additional thermal stress and leading to early boiler failure. Some of the modern units, however, are manufactured with an intermediate size of furnace tube and are capable of firing all three fuels.

The original convention was to produce two types of shell boiler: one with a small combustion chamber and many fire-tubes for firing gaseous or liquid fuels: and one with a larger diameter combustion chamber and fewer fire-tubes for firing solid fuels. The design variation resulted not only from the need for more space to incorporate

Recent design trends have been towards incorporating many more fire tubes of a smaller diameter in the boilers to make them more compact. However, one of the major advantages of the older types of shell boiler is their very large water content which provides a large potential steam reservoir during periods of rapidly

35

Multi-tubular shell boilers dominate the market for outputs between 3 and 20 MW. Even below 3 MW, derivatives of this basic design predominate.

increasing load. The large water surface area also results in drier steam. Modern designs eliminate this advantage, making shell boilers behave more like water tube units, but at the same time the lower water content of the modern boilers means that they can generally be heated through and brought on-line more quickly.

9.1.3 REVERSE FLAME OR THIMBLE BOILERS

Boilers rated up in 12 MW are usually supplied with a single burner or stoker and those between 12 and 20 MW with two burners or stokers, each in a separate furnace chamber. In some of these twin furnace units the flue gases from each chamber are kept separate until they meet at the boiler exit.The advantage of this is that it is possible to operate the plant with only one burner firing, giving a much lower minimum output from the boiler. If the flue gas passages are combined, single burner firing may result in the flue gas temperature falling too low, thereby causing corrosion.

As indicated above, the major problem with multitubular shell boilers is thermal stress brought about by differential expansion. The expansion of the furnace tube is much higher than for the first pass of smoke tubes - and this, again, is higher than for the second pass. This puts stress on the tube plates supporting each end of the boiler. The reverse flame or thimble boiler is an attempt to 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.)

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combustion chamber is only attached to the front tube plate.

a cold start-up. They therefore react very quickly to load fluctuations.

These boilers are still classified as three-pass units but two passes occur within the combustion chamber as the flame reverses and only one pass involves convective fire-tubes. In practice the additional heat transfer from the second pass through the combustion chamber is relatively low making this design little better than a two-pass conventional shell boiler

Unlike the conventional water tube boiler there is no steam/water separation header drum (Figure 14). The water, as it is pumped through the combustion chamber, partially flashes into steam, and then passes through a steam separator so that dry process steam is available.The water from the separators is then returned to the feedwater for recirculation.

The other main advantage of the reversing flame is that it reduces the length of combustion chamber required making the boiler more compact. Space is often a problem when hot water or steam boilers are installed within existing boiler-houses or buildings, so the relatively small floor area required by a thimble boiler can be an advantage.

Heat transfer rates can be improved by reducing the stagnant layers of gases and water that adhere to both sides of a heat transfer surface: stirring or increasing the turbulence can achieve this. Fundamental to the design of a steam generator is the maintenance of a high level of turbulence in both the water and the flue gases: this ensures high heat release rates and good thermal efficiency.

As there are relatively few short fire-tubes in the final pass, heat transfer rates are low resulting in high flue gas exit temperatures. Heat transfer can be improved by increasing the turbulence within the flue gases, and many manufacturers fit metal spirals or ‘turbulators’ within the tubes to improve efficiency.

Its small physical size, lightweight construction and rapid steaming potential make this type of boiler especially suitable for decentralised steam distribution systems. It does, however, have two disadvantages: because of its very high evaporation rate good feedwater quality is essential, usually necessitating the use of demineralised water; secondly, the steam generator does not cope well with high impulse steam loads.

Units of this type are currently manufactured for both steam and hot water production and are available in the 150 kW – 3 500 kW range. The flame-shape requirement means that only fuel oil or gases can be used, and most boilers of this type operate most efficiently when fired by fuel oil.

Where a high peak demand occurs for a relatively short period it is better practice to fit a smaller steam generator together with a steam accumulator, which gives a reserve of steam similar to that, provided by a conventional shell boiler

9.1.4 STEAM GENERATORS

Steam generators are manufactured to provide outputs ranging from 75 kW to 2.5 MW (a few hundred to 3,000kg/hr). Their major advantage is that they occupy very little space, even when allowance is made for water treatment equipment. They can therefore be sited almost anywhere within a factory. This means that if new

Steam generators are derived from the water tube type of boiler. In practice they are small forced-circulation water tube boilers. As manufactured they are very compact, lightweight and capable of producing steam very rapidly from

37

equipment is installed requiring steam at, say, 10 bar, and if the existing distribution system is at 7 bar, a single generator dedicated to that new equipment could readily be installed. The alternative is to increase the existing distribution pressure, which may not be possible from an engineering point of view: even if it is feasible, heat and leakage losses will significantly increase.

the generation of low and medium temperature hot water (LTHW and MTHW). Within the 1030kW output range only small steel and steel sectional boilers provide any competition. At higher output levels there is competition first from modular and condensing boilers (subsequently described) and then from the thimble boiler up to about 750 kW.

Figure 14: A steam generator. (Source: ETSU) (Good Practice Guide 30. Page 54. Figure 32.)

The major advantage of the cast iron sectional unit is that it is much more resistant to corrosion than an equivalent steel boiler when flue gas temperatures fall too far. When firing natural gas or LPG this consideration is trivial, but it is of much greater significance when firing fuel oil or coal. Another advantage is that the method and the robustness of its construction reduces the effect of thermal stress making it ideal for small space-heating applications where the burner will fire ‘on’ and ‘off’ quite frequently.

9.1.5 SECTIONAL BOILERS Cast iron sectional boilers are an oddity in that they do not obviously fall into one of the two fundamental boiler categories described above. In principle, however, they more closely resemble a shell boiler. For many years cast iron sectional boilers dominated the low output end of the market for

38

level to avoid condensation and corrosion. For LTHW applications, with water temperatures of 80ºC and below, this has always proved impossible in practical terms and, as indicated in the previous section, the solution has been the widespread use of cast iron sectional boilers.

To some extent the cast iron boiler’s preeminence is being challenged by stainless steel welded boilers which are more compact, much lighter in weight and more energy efficient. However, the former unit still offers a cheap and very tolerant package suited to LTHW applications.

The cooled combustion products of natural gas are only very slightly corrosive compared with oil or coal.This means that all the heat - both sensible heat and the latent heat of the water vapour produced during combustion - can safely be recovered, and condensing boilers have therefore become a practical alternative. These basically involve the incorporation of a heat exchanger in the exhaust flue as shown in Figure 15.

9.1.6 CONDENSING BOILERS The problem of corrosion caused by condensing flue gases has plagued boiler designers for many years. Hot flue gases may be wasteful from an energy point of view but their natural buoyancy in a chimney means that combustion air is drawn into the boiler and flue gases can be removed without using electrical energy to drive fans. Until recently, therefore, boilers were designed to maintain flue gas temperatures at a sufficiently high

Because some corrosion will still occur, the original designs used two different materials for the heat exchangers: cast iron and stainless steel. Stainless

Figure 15: Condensing boilers. (Source: ETSU) (Good Practice Guide 30. Page 56. Figure 33.)

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9.1.7 MODULAR BOILERS

steel heat exchangers are now more widely used because they are very much more compact and so can be fitted to boilers as small as 30kW. Units are now manufactured up to 600 kW and the principle can still be applied to larger units: in the latter case, the heat exchanger is referred to as a condensing economiser.

Where the demand for heat varies on an hourly, daily and monthly basis, as with space heating for large commercial premises, the installation of a single large boiler is not very efficient. A boiler is most efficient when operating continuously at about 85% of its rated output so. Under these circumstances, it is more energy efficient to install several smaller boilers and to operate only the number necessary to meet the heat demand.

In general, these units are fired using natural gas or LPG. As it is the sulphur content of the fuel that is responsible for the corrosion, any low sulphur or ‘clean’ fuel can be used.The alternative is to clean the flue gases before the flue vapour is condensed, so for larger boilers a condensing economiser might be installed after a flue gas desulphurisation process.

The logical outcome of this reasoning is the installation of ‘modular boilers’ consisting of a number of identical small units controlled in cascade fashion. The earliest systems used conventional cast iron sectional or small steel shell boilers and, for larger installations, this has remained the case. However, high-efficiency heat exchange units have been specifically designed for the lower end of the output range.

The energy from the heat exchanger is used to pre-heat the feedwater going to the boiler. The lower the feedwater temperature, the more heat is recovered by the heat exchanger thereby increasing the efficiency of the complete boiler package. Figure 16 shows that efficiency improvements of up to 10% are achievable.

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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cross between a shell boiler and a water tube boiler. This type of boiler is used to burn two different fuels - often a waste product or waste heat and a conventional hydrocarbon fuel. The waste or solid fuel is fired in one combustion chamber and the hot combustion gases pass to a second combustion chamber where the conventional fuel is fired to make sure that total combustion has been achieved. Depending on the design, the hot gases from the first chamber may pass over part of the boiler heat transfer surfaces before entering the second chamber. Alternatively, the gases may only pass through the boiler after combustion has been completed.

many turndown stages allow individual units to operate close to their maximum efficiency at all times. In a well designed system no water circulates through the boiler when it is off, and this reduces the potential heat loss. Figure 17 shows the type of pipework and valve layout that would typically be installed. Such systems are under fully automatic control and are either oil or gas fired. There is no upper limit to the maximum output from a modular boiler set because, if more heat is required, another boiler or heat exchanger unit can be added. The basic building blocks of the system start at about 10kW but units of 100kW or more could equally be used. A full financial assessment would be required to define the ideal modular boiler set for a particular potential installation.

It is becoming increasingly popular to take advantage of the energy stored in various industrial and commercial wastes rather than to

Figure 17: Schematic of Modular Boiler System. (Source: ETSU) (Good Practice Guide 30. Page 58. Figure 35.)

incur the often considerable expense of disposal. Originally, use was made of conventional incinerators attached to waste heat boilers, but the efficiency of heat recovery was usually low.The

9.1.8 COMPOSITE BOILERS A composite boiler is not, as its name implies, a

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hourly, a daily or a seasonal basis, will be met more efficiently if several smaller boilers are installed.

composite boiler is one outcome of an ongoing design and development programme for waste burning boilers, which has been undertaken by manufacturers.

9.2 BOILER SYSTEM SELECTION •

The third step is to identify the appropriate boilers for the job. The flowchart in figure 18 offers guidelines for the selection of steam boilers based on the output and conditions required. Generally, for each output level several boiler choices are available.

The first decision involves the selection of a steam or hot water system: the appropriate choice is usually very clear.The next step is to evaluate the overall size of the system and how the load is likely to fluctuate. A large steady load ideally requires large boilers, but a load, which fluctuates on an

Small boilers are fuelled only by gas or oil, so the costing is fairly simple. All fuel options, however, are open in the case of the larger boilers so more information on capital, operating and maintenance costs must be obtained either from equipment manufacturers or, possibly, from existing plant users. In all cases, when the selection of new or replacement boiler plant is undertaken consideration should be given to the installation of Combined Heat and Power (CRP) schemes.

This Guide has examined the various problems associated with boilers, fuels and pollution. If all these factors are taken into consideration, boiler system selection becomes more difficult, and additional guidelines are required.

Figure 18: Boiler selection flow chart for steam boilers. (Source ETSU) (Good Practice Guide 30. Page 74. Figure 41.)

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10. energy and cost saving for boilers

••••••••• 10.2 BOILER ENERGY BALANCE •

4

10.1 POTENTIAL LOSSES •

To optimise the operation of boiler plant it is necessary to understand where energy wastage is likely to occur. Figure 19 shows all the inputs and outputs for a typical oil or gas-fired boiler. With coal-fired plant there would be additional losses in the heat and combustible content of the ash. For an oil-fired steam boiler with the characteristics listed below an overall thermal efficiency of 75% is normal under typical operating and maintenance procedures. Boiler rating Steam Pressure Feed Water Temperature Flue Gas Temperature

The three sources of boiler heat energy input are the fuel, feedwater and combustion air. The major energy source is from the fuel, which can be 3 expressed in terms of MJ/m for gas and MJ/L for oil. In the case of some oils it is necessary to heat the oil in the storage tank sufficiently to permit pumping and then heat it further prior to going to the burner. The thermal energy of the oil as it is delivered to the boiler should be added to the higher heating value of the oil to represent the total fuel energy input.

2.7 MW 7 bar g 50ºC 232ºC

The feedwater temperature must also be

Figure 19: Boiler inputs and losses. (Source ETSU) (Good Practice Guide 30. Page 77. Figure 43.) 4

A 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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Figure 20: Boiler Energy Balance. (Source: ETSU) (Good Practice Guide 30. Page 77. Figure 43.)

considered as part of the energy input (i.e. higher temperature feed-water requires less heat energy from the fuel to be converted to steam). The feedwater temperature can be used to determine this heat energy input level.The energy content of the feedwater is the enthalpy (hf) as determined in steam tables corresponding to the feedwater temperature.

10.3.1 MAINTENANCE SAVING OPPORTUNITIES Some significant energy savings can be made by careful maintenance, specific examples are given below: 1. Maintain proper burner adjustments. It is a good idea to have an experienced burner manufacturer’s representative adjust the burners. The operator can then identify the appearance of a proper burner flame for future reference. The flame should be checked frequently, and always after any significant change in operating conditions. 2. Overhaul regenerative air heater seals. Excessive amounts of air can leak from the air side to the gas side of the air heater if the seals are in poor condition.This results in increased forced draft fan power consumption and may reduce the maximum boiler capacity. 3. Check boiler easing for hot spots.“Hot spots” are an indication of excessive heat losses from the boiler enclosure. The temperature of the surface of the outer skin should not be more than 50ºC, although higher temperatures may

Combustion air is normally drawn from within the boiler plant, but it may be ducted from outside and heated with steam. A higher combustion air temperature will reduce the energy input required from the fuel.

10.3 MINIMIZING BOILER LOSSES • Energy loss is a crucial topic in terms of efficient boiler plant operation. The losses that follow can be influenced by design and operating factors. The major controllable heat losses and hence the target areas for improvement are detailed below.

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4.

5.

6.

7.

is a tendency to increase the air flow to ensure that the fuel-air ratio will not become excessive for load changes or upset conditions. If the fuel-air ratio is too high, meaning that there is a deficiency of combustion air, there is a possibility of unstable combustion conditions, which could lead to a furnace “puff ”. A properly operating combustion control system will permit operation at the lowest attainable excess air level while maintaining proper combustion during load changes. Typically a reduction in the excess air from 20 to 10 per cent will increase the efficiency 1.5 per cent.

be unavoidable where insulation cannot be installed, such as around the burner assembly. Eliminating hot spots is a safety measure, and will help to maintain comfortable working conditions. Replace or repair missing and damaged insulation. Substantial quantities of heat are lost from bare steam and hot water lines. Replace boiler doors and repair leaking door seals. Leakage of air or gas will create the same problems as described in Example 4. In addition, an open furnace door will cause considerable heat loss by radiation of heat from the furnace to the outside.There is also a danger that a furnace upset will cause hot gas to be ejected suddenly through the opening to create a personnel safety hazard. Repair malfunctioning steam traps. Steam traps may fail in the open or the shut position. An open steam trap will pass excessive quantities of steam to increase the heat loss. A closed trap will not permit condensate to escape. If the trap is connected to a heat exchanger, the heat exchanger will gradually fill with condensate and eventually fail to operate. If the heat exchanger is heating outside air, the condensate may freeze in winter and damage the tubes of the unit. If the closed trap is draining a steam line, excessive condensate may build up in the line to cause water hammer in the system.This may damage fittings and equipment. A regular steam trap maintenance program is a very positive step toward minimizing energy losses. Calibrate and tune measurement and control equipment. A common cause of deteriorating boiler efficiency is operation at higher excess air values than necessary. If the combustion control system is not operating properly there

10.3.2 BLOWDOWN HEAT LOSS This loss varies between 1% and 6% and depends on a number of factors: • total dissolved solids (TDS) allowable in the boiler water: • the quality of the make-up water, which depends mainly on the type of water treatment installed (e.g. base exchange softener or demineralisation): • the amount of uncontaminated condensate returned to the boilerhouse: • boiler load variations. Correct checking and maintenance of feedwater and boiler water quality, maximising condensate return and smoothing load swings will minimise the loss. The installation of blowdown heat recovery systems will help to control the loss.

EXAMPLE Diverting the flash steam to the de-aerator and/or putting the blowdown water through heat exchangers to heat the feedwater make-up can recover blowdown heat.

45

Consider a boiler evaporating 13 500 kg/h of dry saturated steam at 1400 kPa (absolute) with a blowdown 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 50 Annual savings = 6 Annual savings = 1 x 10 = R10 506 Blowdown heat recovery equipment including a heat exchanger to transfer heat from the blowdown water to treated water make-up, plus the associated piping, costs in total about R150, 000. Simple payback = R150000 Simple payback = Simple payback = R105060 = 1.4 years

10.3.3.1 RADIATION HEAT LOSS

10.3.3 HEAT TRANSFER

The radiation heat loss of a boiler is primarily a function of the applied thermal insulation. Insulation reduces the heat radiating from the boiler and maintains the outside surfaces at a temperature low enough for safety. The surface temperature normally determines the quality and thickness of the insulation on the various sections of the boiler. Most safety regulations require that metal surfaces within reach of personnel not exceed 500C. The heat loss from the casing is difficult to measure accurately. Figure 21 is derived from the American Boilermakers’ Association Standard Radiation Chart, and can be used to estimate the heat loss. Radiation loss is independent of the type of fuel fired, and use of this chart requires only knowledge of the output rating of the boiler and the nature of the furnace walls.

In modern shell and water tube boilers some 70% of the total heat transfer takes place in the combustion chamber by radiation. The three factors 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, which fills the combustion chamber without impingement, satisfies all the criteria for satisfactory heat transfer.

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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/h with all four furnace walls water cooled. From the chart, the heat loss due to radiation would be 0.65 per cent of gross heat input. Note that if the boiler were operating at half capacity, the radiation loss would be 14 per cent of gross heat input. It can therefore be seen that a penalty will be paid, in increased percentage radiation losses if a boiler is operated on part load for an extended period of time.The absolute heat loss to the flue gas would be lower at part load, because the gas volume is lower. However, the overall boiler efficiency would likely be lower. The remaining 30% of heat transfer is by convection from the hot flue gases and this is determined mainly by the flue gas velocity and degree of surface fouling.The fouling of heat transfer surfaces is a result of soot and ash on the fire side and incorrect water treatment on the water side. In order to minimise the thickness of the boundary layer limiting heat transfer rates modern shell boilers use smaller multiple tubes and 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: Boilers installed 15 to 20 years ago were sometimes insulated for reasons of personnel protection rather than energy conservation. Insulation thickness was selected to give an outside casing temperature of 55ºC. If additional insulation was added to reduce the skin temperature to 40ºC, the energy saving could amount to at least 0.25 per cent of the annual fuel bill. Also, some areas out of the reach of operating staff may not be insulated.

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The effect on boiler efficiency of reducing excess air is shown in Figure 22.

10.3.4 EXCESS AIR REDUCTION 10.3.4.1 THE SIGNIFICANCE OF

When setting up a combustion system the aim is to use the minimum amount of excess air, which will ensure clean safe combustion. This minimum will depend both on the type of fuel and on the type of burner/stoker employed. Table 7 gives guidelines for good practice concerning the quantities of excess air required for four different fuels. Newer equipment should be able to achieve the lower values in the range, but some older equipment will have difficulty achieving even the higher values.

EXCESS AIR For every fuel it is possible to calculate the exact amount of air that is needed for combustion. In practice, some surplus air is required to ensure complete combustion, the amount varying with the type of fuel being burned. Any further excess air is heated, passes through the boiler and is passed out of the stack, thereby reducing system efficiency.

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 Natural Gas Fuel Oil: Light Heavy Coal NB

Excess Air (%) Min 10.0

Max 15.0

O2 in Flue Glass (%) Min Max 2.0 2.7

12.5 20.0 30.0

20.0 25.0 50.0

2.3 3.3 4.9

3.5 4.2 7.0

the above settings are typical for boilers without low excess air combustion equipment.

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Simply adjusting the excess air is not necessarily sufficient: the air must mix with the fuel at the correct point. Almost all combustion systems use two sources of combustion air: the air which immediately mixes with the fuel to initiate combustion (the primary air): and that used to complete the combustion (the secondary air). It is essential that these are available in their correct ratio to obtain complete, clean combustion.

10.3.4.2 AUTOMATIC CONTROLS Automatic controls may be added to a boiler system to ensure correct air ratios. In this case a number of factors, such as the boiler firing rate, can be incorporated within the system. The initial setting up of this type of computer-based system requires the O2 at a number of firing rates to be input, usually in the form of a straight line. Many systems incorporate a self-learning capability, which will modify the initial program, tailoring it exactly to the characteristics of an individual boiler burner/stoker configuration.

Unless there is a system for regularly checking the flue gas constituents, greater excess air has to be used to allow for variations in the operating parameters.These might include: • • •

10.3.5 FLUE GAS HEAT RECOVERY

changes in fuel composition - especially for coal and heavy fuel oil; changes in the density of air between summer and winter, wet to dry etc; wear and tear, standard of maintenance, and the age of the combustion equipment.

Most of the heat losses in a boiler are in the flue gas.The flue gas temperature should be as low as possible above the dew point of sulphur gases, which could condense into acids, attacking the stack and associated equipment.

EXAMPLE A boiler burning natural gas is operating at 60% excess air. Boiler efficiency has been tested and found to be 77%. Annual fuel costs are R4 000 000. Recalibration of the controls and minor repairs to the burner windbox 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 a flue gas temperature of 210ºC. Assuming that other losses and the flue gas temperature remain unchanged, the boiler efficiency will be 79%. Annual Annual Annual Annual

fuel cost at 40% excess air fuel cost at 40% excess air fuel cost at 40% excess air savings

Payback Payback Payback

= = = = = = = =

R4 000 000 R4 000 000 R4 000 000 R4 000 000 R101 270 R20000 R101270

x 77 = x = x 79 = - R3 898 730 = = =

R3 898 730 R3 898 730 R3 898 730

0.2 year (2.4 months) 0.2 year (2.4 months) 0.2 year (2.4 months)

By ensuring that the flame is of a clear bright colour and nearly fills the combustion chamber, and that excess air is kept to a minimum, an increase in overall thermal efficiency of some 5% can be achieved.

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also been installed. These consist basically of a water jacket round the stack.

Figure 23 shows the typical corrosion curve for a fuel oil and indicates two temperature hands where severe corrosion will occur: around the acid dew point, where concentrated acids chemically attack the metal, and around the water dew point, at which point the acids are much diluted and become even more corrosive.

The increase in overall thermal efficiency achievable by using recovered heat to increase the feedwater temperature is shown in Figure 26. In general, for every 1ºC increase in feedwater temperature there is an approximate drop of 4ºC in the flue gas temperature.

All fuels display this pattern, but the upper or acid dew point temperature depends on the amount of sulphur present in the fuel (Figure 24). In order to prevent corrosion becoming a significant problem, either in the boiler or in the exit flue and chimney, a temperature above the acid dew point must be maintained. Most modern three-pass shell boilers have flue gas exit temperatures around 200ºC and, except when firing a clean fuel (i.e. natural gas, LPC or gas oil), it is uneconomic to attempt heat recovery.

In the case of clean fuels with a minimal sulphur content it is possible for flue gas exit temperatures to be below the water dew point temperature without causing significant corrosion problems, as shown earlier for condensing boilers. A condensing economiser is merely an extension of this principle. The introduction of an economizer into the boiler breeching will increase the pressure drop in the flue gas system. In a forced draft boiler, this may mean the installation of a new forced draft fan, or at least a new impeller and motor. The resultant increase in combustion chamber pressure may necessitate changes to the burner. In an induced draft system, the induced draft fan may be changed, but the combustion chamber pressure and burner will remain the same.There will be an additional water-side pressure loss that may mean a modification to the boiler feed pumps and motors. The temperature of the gas to the stack will be less, which reduces the stack draft. Feedwater piping modifications, economizer support, and possible breeching modifications must be evaluated.

10.3.5.1 ECONOMISER INSTALLATION Flue gas economisers have been in use for a long time on both shell and water tube boilers of older design. Most of these consist of large cast iron heat exchangers. Cast iron is used because it is more resistant to the acid corrosion, which is inevitable at start-up and shut-down. Figure 25 shows a simple schematic of a boiler economiser arrangement. Much simpler but less efficient economisers have

Example The analysis that follows is based on the actual addition of a free standing economizer to a forced draft packaged 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 GJ at 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 0.2 per cent of the fuel input can be allowed for the economizer heat transfer efficiency of approximately 96 per cent.Thus, the heat recovered in the economizer = 4.8 - 0.2 = 4.6 per cent of fuel input. Annual steam heat

Fuel energy after conversion Fuel energy after conversion Fuel energy after conversion

Annual fuel cost after conversion

Annual fuel savings Simple payback Simple payback Simple payback

=

292 780 x 0.8

=

234 224 GJ

= = =

234224 (0.80 + 0.046)

=

276 860 GJ

=

276 860 x 42.4

=

R11 738 860

= = = = = =

R12 413 870 – 11 738 860 R675 010 R1580000 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 could reduce temperatures to 200ºC, increasing the feedwater temperature by 15ºC and raising the overall thermal efficiency by 3%. For a modern three-pass shell LTHW boiler firing natural gas with a flue gas exit temperature of 140ºC a condensing economiser would reduce the exit temperature to 65ºC, giving an increase in thermal efficiency of 5%. An economiser must be correctly sized so that the heat transfer does not cause the water temperature to exceed the system operating temperature or to be flashed off to steam.

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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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Figure 26: Feed-water temperature and boiler efficiency. (Source: ETSU) (Good Practice Guide 30. Page 89. Figure 58.)

commonly used as they require little additional equipment.

10.3.6 COMBUSTION AIR PRE-HEAT Combustion air pre-heat has always been regarded as the poor cousin of the economiser because air pre-heaters are large and less efficient overall. In order to improve thermal efficiency by 1% the combustion air temperature must be raised by 20ºC. Furthermore, most gas and oil burners used on boiler plant were not designed for high air pre-heat temperatures and a maximum increase of 50ºC is usually all that can be tolerated.

When considering an airheater, the burner manufacturer should be consulted to determine the maximum allowable combustion air temperature. This could be as low as 250ºC, and it is unlikely to be higher than 400ºC since that would require alloy steels instead of carbon steel. The introduction of an airheater will increase the pressure loss on the flue gas and combustion air systems. A forced draft system, with only a single F.D. fan, may require the insulation of a new fan and motor. For a balanced draft system, both fans may have to be replaced, although a new impeller and motor might be sufficient. The forced draft system may also include modifications to the burner, as the combustion chamber pressure will increase significantly. New air and gas ductwork must be installed, and modifications to the stack may be necessary.

The usual heat sources for combustion air preheating include: •

heat remaining in the flue gases:

•

higher temperature air drawn from the top of the boiler house:

•

heat recovered by drawing the air over or through the boiler casing to reduce shell losses.

Modern burners are, however, available which can stand much higher combustion air pre-heat

The two latter sources tend to be the most

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or not, so a boiler having a shell loss equivalent to 2% of fuel fired at full firing will have a loss equivalent to 6% at one third firing.

temperatures. It is therefore possible to consider installing a heat exchanger in the exit flue as an alternative to an economizer. Figure 27 shows the energy-saving potential of this technique.

At lower firing rates the flame does not fill the furnace chamber so heat transfer rates fall. This is compensated for in the reduced flue gas velocity through the convection tubes.

The combustion air intake can sometimes be relocated to the top of the boiler house to use heated air and save energy, as in the example that follows.

In the case of fuels containing significant sulphur content, continuous firing below 30% of rated boiler output may result in boiler metal temperatures falling below the sulphur dew point. This, in turn, can cause smutting and, possibly, rapid corrosion.

10.3.7 LOAD SCHEDULING When a boiler is being operated at low loads some of the losses remain constant and are not dependent on the firing rate. Shell losses resulting from radiation and convection, for instance, remain largely the same whether the burner is operating

The best practice is to use boilers that will operate 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 the top of the boiler house increases the average air temperature to 30ºC.The specific heat of the air is 1.01 kJ/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 Annual fuel savings Annual fuel savings

= = = =

The ducting cost is R100 000. Simple payback = Simple payback = Simple payback =

146 450 x 6000 x 50 6

1 x 10 R43 930 per year

R1000000 R43930

= 2.3 years

Generally, the savings achieved will depend on the type of system installed. Ducting hot air from the top of the boiler house typically results in savings of 1%, while savings of 2% are more typically achieved by drawing combustion air over/through the boiler casing.

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Figure 27: Efficiency increase versus air pre-heat. (Source: ETSU) (Good Practice Guide 30. Page 91. Figure 59.)

Steam systems that have low base loads but high peak demands over relatively short periods always cause fuel efficiency problems. Older boilers had a very high thermal storage capability because of their very high water content, but modern practice produces boilers with many more tubes and much less water. In some cases, therefore, a smaller boiler firing at a steady higher rate into a steam accumulator as shown in Figure 30 is a more thermally efficient solution.

normal firing conditions. For LTHW and MTHW systems this is easily achieved using a modular boiler system. For steam boilers, however, the solution is not so simple since, in many cases, each boiler is rated to meet the plant’s maximum load requirement. Where the steam is used for process and space heating there will be a significant reduction in load once the space heating is turned off in summer.A smaller boiler, correctly sized for the summer load should therefore be installed.This also applies in the case of lame hot water systems.

Figure 28: Schematic of a steam accumulator. (Source: ETSU) (Good Practice Guide 30. Page 84. Figure 52.)

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particularly true when a number of boilers are connected to a common header and are operated in a cascade manner.

Matching the load can result in a thermal efficiency improvement of around 2%. The cost saving resulting from the prevention of sulphur corrosion by proper load scheduling may be much greater.

The best-known solution is to install dampers in the exit flues. In the past the main problems encountered included designing dampers that were virtually gas tight, and incorporating a control system that would prevent the boiler firing against a closed damper.

10.3.8 ON-LINE CLEANING Metal surfaces in the path of the combustion gases need regular cleaning to remove sooty deposits, especially when firing solid fuels. Soot blowers of various kinds have been used to remove soot and dust both from shell and water tube boilers and from economisers and air pre-heaters.Traditionally these comprised high-speed steam or compressed air jets, but recent developments have produced infra-sound and ultra-sound units. The correct installation and use of soot blowers reduces maintenance and retains the optimum efficiency of the plant over an extended period.

Today, automatic gas-tight shut-off dampers for installation in a boiler exit flue are widely available (Figure 29). In the case of forced draught (FD) oil and gas burners a cheaper alternative is available, particularly for retrofit situations: this involves the installation of an automatic damper at the combustion air fan inlet. It is difficult to put an exact figure on the potential saving from shut-off dampers as each boiler installation has different operating parameters and operating periods. A saving of 1% in fuel consumption is, however, usually achieved.

Incorrect water treatment can lead to scale formation, which is a much better insulator than soot or ash. It is not only lack of water treatment that causes the problem, however. In many instances, over enthusiasm in adding treatments, on the basis that ‘a bit more will be even better’, leads to the formation of insulating coatings on the water side of heat transfer surfaces.

10.3.10 VARIABLE SPEED FAN DRIVES The overall potential of modem variable speed drives has been widely explored. For large boiler plant fitted with induced draught (ID) fans, the control of combustion air is generally achieved by throttling the damper. These dampers, however, tend to be designed more for simplicity and reliability than for accurate control and most give a very poor control characteristic at the top and bottom of the operating range. Multi-opposedbladed dampers and iris type dampers have much better control characteristics.

Incorrect water treatment, poor combustion and poor cleaning schedules can easily reduce overall thermal efficiency by 2%. However, the additional cost of maintenance and cleaning must be taken into consideration when assessing savings.

10.3.9 FLUE SHUT-OFF DAMPERS

If the load characteristic of the boilers is variable, it maybe economic to replace the dampers with a variable speed drive. However, up to now there has been very little experience of using such drives with individual boilers rated at up to 20 MW.

For situations where boilers are regularly shut down because of changes in load, the heat loss caused by the chimney effect drawing cold air through the boiler can be significant. This is

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Figure 29: Schematic of a flue shut-off damper and interlock. (Source: ETSU) (Good Practice Guide 30. Page 86. Figure 53.)

10.3.11 INTEGRATED CONTROL

•

faults are recognised and reported more quickly;

Major advances in control technology using the microprocessor have entirely changed strategies for control. Historically each part of a process or plant was treated individually, the appropriate controls being fitted for temperature, flow etc. With microprocessor contacts, the process can be examined as a whole, allowing all aspects to be optimised simultaneously. This type of control is now available for boiler plant.

•

a decline in performance is recognised at an earlier stage; and

•

maintenance scheduling can incorporated into the system.

be

The automatic control of plant items begins with the boiler and combustion system: this can be designed to include sequencing of the boilers to ensure that the correct number of boilers of an appropriate capacity is on line to meet the expected demand. This will maximise overall efficiency.The water treatment equipment will also be subject to automatic control, normally including the automatic regeneration of ion exchange beds. Outside the boiler house, changes in process requirements, reflected in the rate at which temperature or pressure varies, can be used to anticipate the extent of future load swings.

The control can be as simple as the oxygen trim control already mentioned or can involve a completely integrated system that operates the boilers and all the associated equipment automatically. The only limit to the amount of information that can be gathered is the number of sensors and signal converters installed. Equally there is no limit to the number of plant items that can be controlled using the information collected.

The only limit to such a system is the imagination of the control designer. However, not all the functions of a sophisticated controller need by

The advantages of a centralised control system are numerous, and include the following:

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the portion of the primary fuel energy lost in the boilerhouse. The main heat losses for a typical installation, 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).

used: they can simply be there for application as and when required.

10.4 WHAT TO DO FIRST – A QUICK CHECKLIST • The boilerhouse is very often the largest single user of energy on a site, and it is important that its performance is under constant review. There should be a comprehensive boilerhouse logging programme in place, which includes the monitoring of the following parameters: • • • • •

Methods which can be used to assess these losses are detailed in “Saving Energy and Money” booklets which cover, amongst other things, the economic use of oil-fired, gas-fired and coal-fired boiler plant respectively.

fuel consumption; heat output; flue gas conditions; make-up water consumption; subsidiary electricity consumption.

A significant amount of electrical energy is used in the typical boilerhouse for circulating pumps, combustion fans, etc. Where a dedicated kWh meter is installed for the boilerhouse this should be read regularly, though an estimate of electricity consumption can be determined from motor duties and running hours if necessary.

The frequency of checks will depend on the plant and manpower availability, but weekly or preferably daily checks should be made. An important measure of the performance of a boiler plant is the specific boiler efficiency.This is the ratio between useful heat production and energy consumed, i.e.:

Make-up water consumption should be monitored to give early warning of system leaks. The recovery of uncontaminated condensate on steam systems should be maximized, saving on energy, water and chemicals. Where there are significant year round requirements for process heating, typically in excess of 5,000 hours/annum, the feasibility of combined heat and power (CHP) should be investigated.

Heat transferred to heating medium: (usually steam or water) x 100% Fuel Input The heat transferred to the heating medium cannot normally be determined directly, though indirect measurements, such as fluid temperatures, pressure and volume flow rates can be used. Electronic combustion analysers can be used to check efficiencies and monitor trends, particularly before and after maintenance.

10.4.1 CHECK LIST • • • •

In addition it is always worth undertaking a more comprehensive boilerhouse audit, to highlight heat losses and take into account subsidiary energy usage.The biggest part of this exercise is to assess

•

58

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

•

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 plant not firing.

• •

Ensure that boilers and heat distribution systems are adequately insulated. Blowdown steam boilers only when necessary. Ensure as much condensate as practicable is recovered from steam systems. Insulate oil tanks and keep steam or electric heating to the minimum required.

11. TYPES OF FURNACES

•••••••••••••• Figure 31 shows a crucible melting furnace used for nonferrous metals. Metal scrap is loaded into the furnace in batches, and the molten metal tapped off as required.

The purpose of a process furnace is to apply heat to the contents in a controlled manner. The furnace may be used for heating metals to a precisely controlled temperature for heat treatment, or for melting. Furnaces are manufactured in many different types and sizes, some of which are described in this section.

Figure 30 shows a high temperature electric furnace used for the heat treatment of steel.

Furnaces may be batch or continuous type. Furnaces, which generate heat by burning fuel, may be of the direct or indirect fired types. Furnaces are also heated from electric resistance heaters.

11.2 CONTINUOUS FURNACES • Continuous furnaces process the product continually by moving it through the heating zones on chains or conveyors. Since the loading and unloading doors are open all or part of the operating time, there is a significant heat loss through these openings. Continuous furnaces also may have a significant heat loss because of the conveying mechanism, which is heated to the operating temperature with the product. If the conveyor cools off outside the furnace before reentering the loading area, the energy required to heat the conveyor is not used productively.Thus, it

11.1 BATCH FURNACES • Batch furnaces process the product in batches, which means that the furnace doors must be opened and closed at the beginning and end of the batch cycle. Since this is a significant source of energy loss, the loading and unloading times should be minimized. It is also important to load the furnace completely to minimize the energy loss per unit of product.

59

is better if the conveyor stays within the heated furnace area. An example of this type of furnace is shown in figure 32.

with the product being heated in a direct fired furnace. The heat transfer process from the flame to the product is more effective than with an indirect heated furnace, where the flue gas is not in direct contact with the product.The higher rate of heat transfer which can be achieved with direct fired furnaces can lead to local surface overheating of the product, unless the furnace temperature is properly controlled.

11.3 DIRECT FIRED FURNACES • The products of combustion are in direct contact

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.)

60

Figure 32: Continuous type furnace. (Source: Canadian Gov.) (Energy Management Series 7. Page 25. Figure 14.)

11.4 INDIRECT HEATED FURNACES •

higher, resulting in higher heat losses unless heat recovery is used.

In indirect heated furnaces the products of combustion are not in direct contact with the product being heated (Figure 33). Heat is transferred through some form of heat exchanger.

There are a few special considerations for indirect fired furnaces, which affect the heat balance calculations. If a controlled atmosphere is maintained inside the furnace, the heat input and output of the gas entering and leaving the furnace must be included in the heat balance. If heat is required for the preparation of the atmosphere, the energy required in the gas generator must be included as part of the total heat input to the furnace. Electrical energy used for refrigeration or other purposes in the gas generator must also be included.

This type of furnace may be used to provide a controlled environment for oxidizing or reducing, by introducing an artificial atmosphere independent of the combustion process. Since the heat transfer from the flame to the product is not as effective as the direct fired furnace, it can be expected that the flue gas temperature will be

61

Figure 33: An indirectly heated furnace. (Source: Canadian Gov.) (Energy Mangement Series 7. Page 13. Figure 7.)

••••••••• 12. ENERGY AND COST SAVINGS FOR FURNACES

••••••••• 5

boiler energy balance. Energy is taken into the furnace from: • The fuel. This includes both the heat of combustion and the heat carried in as a function of the fuels temperature. • Combustion air. This air entering the combustion chamber contains heat as a result of its temperature. • The ‘feed’. Whatever it is that is to be heated contains heat as a result of its temperature.

12.1 POTENTIAL LOSSES •

As with boilers, to optimise the operation of furnace plant it is necessary to understand where energy wastage is likely to occur.

12.1.1 FURNACE ENERGY BALANCE Basically the furnace energy balance is similar to a 5

A furnace energy efficiency test is described in the appendix.This gives the ‘direct method’ for evaluating efficiency, and a breakdown of the losses.

62

Energy is then lost from the furnace in various forms: • Flue gas. The products of combustion leave the furnace at a temperature higher than incoming fuel and combustion air. • Surface heat transfer. As the furnace temperature is higher than the surrounding environment heat is lost from the combustion zone to the environment as a result of conductive, radiative and/or convective heat transfer. • Escaping furnace air. If the internal pressure of the furnace is too high hot gases will escape to the surroundings through leaks, openings and doors. Conversely if the pressure on the inside of the furnace is higher than the surroundings then ‘cold’ air will be drawn into the furnace, requiring additional heat to maintain a steady furnace temperature.

boilers and have been included in the section on combustion. The major influencing factors are the exit flue gas temperature and the degree of excess air present. Fuel preparation should be correct (uncontaminated and at the right temperature), burners undamaged and properly maintained, and combustion air (both primary and secondary) should be introduced at the right rate and with adequate turbulence.

12.2.1.1 EXCESS AIR REDUCTION A continuous O2 and Combustibles analyser is the best arrangement, but the cost is high. Sampling tests with an Orsat or other chemical means can be a reliable guide to proper combustion conditions. Readjustment of the fuel/air ratio control should be performed promptly if required.

12.2 MINIMIZING FURNACE LOSSES • 12.2.1. FLUE GAS HEAT LOSS

Below table 8 and 9 give a list of typical excess air ratios for various fuels and typical savings that can be realized through excess air adjustment.

The same comments apply here as applied to

Table 8: Standard air ratio for Industrial furnace

Classification Melting furnace for metal casting Steel slab continuous reheating furnace Metal reheating furnace other than steel slab continuous reheating furnace Continuous heat treating furnace Gas generator and gas reheating furnace Petroleum refinery furnace Pyrolyzer and reformer Cement baking furnace Alumina baking furnace and lime baking furnace Continuous glass melting furnace

Standard air ratio 1.3 1.25 1.3 1.3 1.4 1.4 1.3 1.3 1.4 1.3

63

Table 9: Calculated values of % saving

Furnace temperature (˚C)

Air ratio before correction

Air ratio after correction 1.40 1.30

1.20

1.10

1.00

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

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

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

900

1100

64

existing induced draft burners was replaced with a sealed positive pressure burner. The modification also included a blower system for the supply of combustion air, and improvements to the controls to reduce excess air from 15 to 20 per cent before conversion to 8 to 10 per cent. Total cost of the project was R1 200 000.

12.2.1.2 INSTALL A HEAT EXCHANGER IN THE FLUE GAS OUTLET The cost of heat exchangers is significantly affected by the temperature of the gas entering the unit. Careful consideration should be given to introducing cold air into the gas stream, if required, to lower the gas temperature enough to use economic materials. Stainless steels or alloys cannot be used for temperatures above 950ºC.

Before conversion, the fuel consumption per burner was measured at 193 000 kJ/h, or 4.63 GJ/h for the furnace with all burners in service. The furnace operates 6 days per week, 24 hours per day and the allowance for down time or part load operation is 15 per cent. Gas costs R42.40 per gigajoule. Annual fuel cost before conversion = (100 – 15) = x 24 h/d x 6 d/wk x 52 w/yr 100 x 4.63 GJ/h x 42.4/GJ = R1 249 490

If the recovered heat is used to preheat the combustion air, the burner manufacturer should be consulted to determine the maximum allowable air temperature. Frequently, this will be as low as 250ºC. It is unlikely to be higher than 400ºC since that would require alloy steels instead of carbon steel. If it is not practical to heat the combustion air, it may be possible to heat process water or to install a waste heat boiler to utilize the beat energy in the flue gas.

To estimate the savings, it is necessary to determine the recuperator performance. Flue gas leaves the radiant tubes at 1100ºC, and enters the recuperator at this temperature. The gas leaves the recuperator at 650ºC and the combustion air is heated from ambient to 500ºC.

Introduction of a heat exchanger will increase the pressure drop in the flue gas system, which means that the combustion air fan capacity will be reduced. It may be necessary to install a new fan or impeller and drive motor. It is possible that the furnace pressure will be increased unless there is sufficient draft available from the stack to overcome the added resistance across the heat exchanger. Because of these and other possible complications, it is suggested that the furnace manufacturer or a consulting engineering firm be retained to make an evaluation of the proposed changes.

To isolate the performance of the recuperator from other savings, it is assumed that excess air before and after conversion remains at 20 per cent. The intersection of 20 per cent excess air and 1100ºC on Figure 5 (extrapolated) indicates that 64 per cent of the heat supplied in the fuel is lost in the flue gas. Flue gas heat loss/burner= Flue gas heat loss/burner= Flue gas heat loss/burner= =

The economic and technical analysis that follows is based on an actual installation of high-alloy recuperators applied to an indirectly heated, continuously operating, heat-treating furnace. A custom-designed triple-pass recuperator was bolted to the exhaust leg of each of the 24 radiant tube heaters of the furnace, and each of the

64

x 193 000 100 123 500 kJ/h

The remainder, or 69 500 kJ/h, enters the furnace through the radiant tube. After conversion the stack gas temperature dropped to 650ºC. Using 20 per cent excess air

65

of R200 000 the payback period for this project was 2 years.

and 650ºC flue gas temperature shows that about 40 per cent of the heat supplied is lost, and 60 per cent enters the furnace. It is reasonable to assume that the amount of heat entering the furnace through each radiant tube does not change when a recuperator is installed, as the gas temperature leaving the tube remains at 1100ºC. Sixty per cent of the heat supplied per burner after conversion, equals 69 500 kJ/h. Burner energy = 69 500 = 115 800 kJ/h Burner energy = = 115 800 kJ/h Burner energy = 0.6 = 115 800 kJ/h

12.2.2 HEAT LOSS TO INCOMPLETE COMBUSTION This is discussed in the section on combustion. An important aspect of this is the proper mixing of fuel and combustion air in the furnaces burner. Burner Assembly

Flue gas heat loss/burner

= = Energy savings =

Savings Savings Savings

= = = = = =

115 800 - 69 500 46 300 kJ/h 24 (burners) x (123 500 - 46 300) 1 852 800 kJ/h 1.85 GJ/h 1,85 x 100 4.63 40%

It is good practice to have an experienced burner manufacturer’s representative set up the burner adjustments. Furnace operators can then identify the appearance of a proper burner flame for future reference. The flame should be checked frequently, and always after any significant change in operating conditions affecting the fuel, combustion air flow, or furnace pressure has occurred. The installation of a modern design burner assembly can permit operation at lower values of excess air, thus reducing stack losses.A new burner assembly can also be the means to provide full automation for start-up and shutdown. In a multiple burner installation automation will permit start-up and shutdown of burners to follow varying load patterns, rather than modulating the load on individual burners over a wide range. Burners generally operate more efficiently at high loads, so improvements in part load economy can be expected if some burners are shut down.

The actual fuel consumption savings were 48 per cent. Part of the discrepancy is because of the difficulty of measuring flue gas temperatures and airflows, hence excess air quantities accurately.The modification introduced two further areas of potential savings. One of these was the improved airflow control and the resulting reduction in excess air to 8 per cent. The second area of savings results from the changes made to the control system and this is difficult to estimate. Before conversion, burners were operated at a fixed setting and turning selected burners on and off controlled furnace temperature. Heat was lost from the furnace to radiant tubes not in service, because of natural convection of outside air through these tubes.This loss was eliminated with the new modulating control system.

Provision should be made to shut off the combustion air to idle burners. This avoids losses due to excess air entering the furnace and not taking part in the combustion process.

12.2.3 RADIATION HEAT LOSS The annual fuel savings were 48 per cent of R1249 490 or about R600 000. Based on the capital cost

The same comments that were made for boilers

66

= [21.5 MJ/(m2·h) x 12 m2] + [11.6 MJ/(m2·h) x 32 m2] = 692.2 MJ/h

apply here. The radiation heat loss of a furnace is primarily a function of the applied thermal insulation. Insulation reduces the heat radiating from the boiler and maintains the outside surfaces at a temperature low enough for safety.The quality and thickness of the insulation on the various sections of the furnace are normally determined by the surface temperature. Most safety regulations require that metal surfaces within reach of personnel not exceed 50ºC.The heat loss from the casing is difficult to measure accurately.

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 not considered to be significant. Energy savings = 692.2 - 74.8 MJ/h = 617.4 MJ/h

Re-insulating Furnace Enclosure Older furnaces may use refractory brick for the furnace lining. If the furnace has to be rebuilt, it is frequently economical to use ceramic fibre blanket insulation. If refractory brick is required to withstand rough handling, an outer layer of ceramic fibre can be used.

The furnace operates 4000 hours per year, and fuel costs R50/GJ. Annual savings = 617.4 MJ / h x 4000 h / yr x R50 / GJ Annual savings = Annual savings = 1000 MJ / GJ = R123 480/yr

Since ceramic fibre is a much better insulator than refractory brick, care should be taken to ensure that the inner layer of refractory is not overheated, since its average temperature will be higher. During a tour of a plant it is noticed that a furnace appears to be radiating substantial quantities of heat. Temperature measurements of the surface average 200ºC on the walls and 250ºC on the roof.The outside dimensions of the furnace are 2 m by 2 m by 6 m long. It is decided to reinsulate the furnace to give a maximum surface temperature of 50ºC, to provide operator safety and heat savings.

12.2.4 FURNACE PRESSURE CONTROL Maintaining a slight positive furnace pressure can control air leakage into or gas leakage out of a furnace.The control damper in the furnace flue gas ducting or the related control should be readjusted if the furnace pressure is not at the correct value. Replace Warped or Damaged Furnace Doors or Covers

Taking heat losses as 21.5 MJ/(m2.h) at 250ºC, 11.6 MJ/(m2.h) at 200ºC, and 1.7 MJ/(m2.h) at 50ºC. Roof area = = Wall area = =

Furnace doors or covers, which are warped, damaged or missing can be a source of considerable leakage of air into or gas out of the furnace. Doors or covers with tight fitting seals should replace these. Further improvement would result from installing power operators on the doors to minimize the time the doors are open, as well as make it easier for the operators.

2mx6m 2 12 m (2m x 6m x2) + (2m x 2m) 2 32 m

Heat loss before reinsulation

67

Efficiency for furnaces will be defined as the amount of heat taken up by the product versus the heat added in the form of fuel. For a furnace it is important to estimate and trend the changes of efficiency over time. Due to the nature of the process, efficiencies are far smaller than those for a boiler. A small change in efficiency will result in a large change in specific fuel consumption. Any changes are therefore important. In the appendix the ‘direct method’ for furnace efficiency calculations is outlined for a furnace of any kind.

The following example illustrates the possible saving by replacing a missing door. A 0.25 m2 door is noted to be missing from a furnace operating at 900ºC. Heat radiated through the opening is 400 2 MJ/(m .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

As regards monitoring equipment the, minimum suggested is to have the ability to determine the energy used per unit of output, so that significant deviations from this can be identified and corrective action taken.The fuel or watt meter can be a portable instrument which may be used on several furnaces. Additional instrumentation would be required to identify individual losses. Measurement of flue gas temperature and oxygen content can be used to indicate flue gas loss. If a heat exchanger is used to recover heat from the flue gas, temperature measurements of the gas and air in and out of the heat exchanger can be used to check the performance.

= R50 x 400 = R20 000/yr

This saving will be reduced slightly by the heat loss from the closed door. Some additional savings may result from the elimination of air leaking into or gas escaping from the open door.

12.2.5 FURNACE EFFICIENCIES AND MONITORING AND TARGETING High temperature process plant, such as furnaces and kilns, are used in a variety of industries.There is a wide range of plant used, and it may be of a continuous or batch nature. However, the basis under which an energy audit is undertaken on all high temperature processes is very similar.

Relocate Combustion Air Intake to Recover Heat Within the Building

Specific energy consumption = Energy consumption Product throughput

Heat generated inside the plant tends to rise, resulting in significant temperature differences between floor and ceiling. If the furnace has a forced draft fan it is often possible to install lightweight ducting from the ceiling to the fan intake. Alternatively, the ducting may be routed to an adjacent shop if considerable heat is simultaneously being generated and vented outside. Care should be taken to size the ducting adequately to minimize the pressure drop.

This gives a good measure of the relative plant performance, and requires only good production records and energy consumption figures to be kept.

A furnace using 5000 kg/h of combustion air draws inside air at 20ºC average temperature. Installation of a duct to the ceiling increases the average air temperature to 30ºC.

As with boilers, a specific efficiency for the process plant can be calculated but it is more usual to use the specific energy consumption:

68

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 and the fuel costs R50/GJ Annual fuel savings = 50 300 x 6000 x 50 Annual fuel savings = 6 Annual fuel savings = 1 x 10 = R15 090 per year

•

flue gas losses (except on electrically operated 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 of these heat losses to identify areas for potential improvement.

The cost of the ducting is R15 000. Simple payback = R15 000 R15 090 = 1.0 year

•

RECOVERY OF HEAT FROM EQUIPMENT COOLING WATER

•

It is often possible to use the warm water discharge from equipment coolers for purposes such as process washing. In some systems the water discharge may be too cool to be useful. In these instances the installation of a water flow control valve and temperature controller may be helpful. The water flow is controlled automatically from the water temperature at the cooler outlet so that the water temperature is high enough to be useful, while maintaining proper cooling. The control system will also reduce water use.

•

•

• • •

12.3 WHAT TO DO FIRST – A QUICK CHECKLIST. •

•

In a well controlled plant there should be a good correlation between energy consumption and production rate.The more scatter on the graphical plot the worse the process control. The offset on the graph, i.e. the energy consumption at zero production, represents the level of standing losses. These are typically made up of:

• •

6

Minimise heat losses from openings, such as doors, on sealed units. 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 are well worth considering. 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 control should be considered for larger units.

•••••••••

Specific fuel consumption is the ratio of fuel consumed to kg of product heated.

69

APPENDIX CONVERSION TABLES.

••••••••• Table A1: Mass Equivalent

FROM/TO KILOGRAM TON (a) MULTIPLY BY 1 Kilogram 1.000 3 1 Metric 1.000x10 ton (a) 2 1 Ton 9.072x10 (USA) (b) 3 1 Ton (UK) 1.016x10 (c) -2 1 Ounce 2.835x10 -1 1 Pound 4.536x10 (USA) -1 1 Pound 4.124x10 (UK)

METRIC (b)

TON (USA) TON (UK) (c) (USA)

1.000x10 1.000 9.072x10

-3

-1

1.016 -5

2.835x10 -4 4.536x10 4.124x10

-4

1.102x10 1.102

-3

-4

9.842x10 -1 9.842x10

1.000

8.929x10

1.120

1.000 -5

3.124x10 -4 5.000x10 4.545x10

4

-1

OUNCE (UK)

POUND

POUND

3.527x101 4 3.527x10

2.205 3 2.205x10

2.425x10 3 2.425x10

3.201x10 3.584x10

-5

2.790x10 -4 4.464x10 4.059x10

-4

4

4

1.000 -1 1.600x10 1.455x10

1

2.000x10 2.240x10

3

3

2.200

3

2.464x10

6.251 1.000 9.083x10

6.873x10 1.100 -1

3

2

1.00

(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 TO METRE MULTIPLY BY 1 Litre 1.000 3 1 Cubic 1x10 metre 1 Gallon 3.785 (USA) 1 Gallon 4.546 (UK) 2 1 Barrel 1.590x10 (USA) -1 1 Pint 4.732x10 USA -1 1 Pint 5.683x10 (UK) 1 1 Cubic 2.832x10 foot

CUBIC (USA)

GALLON GALLON BARREL (UK) (USA) (USA)

-3

1

1x10 1.000

3.785x10 4.546x10 1.590x10 4.732x10 5.683x10 2.832x10

-1

2.642x10 2.200x10 6.289x10 2 2 2.642x10 2.200x10 3.289 -3

-3

-1

-4

-4

-2

1.000

8.327x10

1.201

1.000

4.200x10 1.250x10 1.501x10 7.481

1

-1

-1

3.498x10 1.041x10 1.250x10 6.231

70

-1

2.381x10 2.860x10

1

-1

-1

PINT (UK) -3

-2

-2

1.000 2.976x10 3.574x10 1.781x10

-3

-1

CUBIC -2

2.113 1.760 3.531x10 3 3 1 2.113x10 1.760x10 3.531x10 8.000

6.662

1.337x10

9.606

8.000

1.605x10

3.360x10 -3

PINT FOOT

8.328x10

2

-1

1.0001 4.984x10

2.799x10 8.328x10

2

-1

4.984x10

-1

5.615 1.671x10

-2

-1

1.0001 1

-1

2.006x10 1

1.000

Table A3: Energy and Heat Equivalent

FROM/TO

JOULE

CALORIE

THERM

BTU

THERMIE

ERG

kWh

MULTIPLY BY 1 Joule

1.000

2.388x10

1 Calorie

4.187

1.000

1 Therm

1.055x10

8 3

1 BTU

1.055x10

1 Thermie

4.186x10

6 7

Erg

1.000x10

kWh

3.600x10

6

2.520x10 2.520x10 9.995x10 2.388x10 8.599x10

-1

9.479x10 3.968x10

4 2 5 8 5

-9 5

1.000

9.478x10 3.968x10

-4 -3

1.000x105

1.000x10 3.967x10 9.479x10 3.413x10

-5 5 -16 -2

1.000 3.967x10 9.478x10 3.412x10

2.389x10 1.001x10

-11 3

-6

2.521x101 2.521x10

3

-7

-4

1.000 2.398x10 8.600x10

1.000x10 4.187x10 1.055x10 1.055x10 4.186x10

-14 -1

7 7 15 10 13

1.000 3.600x10

2.788x10 1.163x10

-6

2.930x101 2.930x10

4

1.163 2.778x10

13

-7

-14

1.00

Table A4: Multipliers and Equivalents

1 Toe

42Gj

1 Tse

29.3 Gj

••••••••• boiler efficiency test

•••••••••••••• Steam generators boiler heat balance and efficiency calculations

identification of the magnitude of all the heat flows into and out of the boiler.

The calculation of the efficiency of a boiler involves a comparison between the energy supplied in the coal with the energy transferred to the feedwater to convert it to superheated steam.

It is therefore possible to calculate the efficiency of a boiler in one of two ways:1) The Direct Method where the energy gain of the working fluid (water and steam) is compared with the energy content of the boiler fuel;

The heat balance on the other hand concerns the

71

proximate analysis and ultimate analysis.

2) The Indirect Method where the efficiency is the difference between the losses and the energy input.

Proximate Analysis is defined as the determination of moisture, volatile matter, and ash, and the calculation of fixed carbon by difference.

Before these two methods are discussed in more detail, it is necessary to define the terminology used.

Ultimate Analysis of a dried sample is defined as the determination of carbon, hydrogen, sulphur, nitrogen and ash, and an estimate of oxygen by difference.

Calorific Value (CV) - The energy released by a fuel when it is completely burnt and when the products of combustion are cooled to the original fuel temperature is known as the calorific value of the fuel.

Analysis on an as-received basis includes the total moisture content of coal received at the plant. Similarly, the as-fired basis includes the total moisture content of the coal as it enters the boiler furnace or pulverises.

The combustion of any fuel with hydrogen as a constituent produces water vapour. If the products of combustion are at a high temperature, the water will leave the system as vapour and will carry with it the energy represented by the energy of superheated steam. However, if the gases are cooled, the vapour will condense and reject this energy.

The Direct Method of Boiler Efficiency Calculation As mentioned earlier, the direct method consists of a direct comparison between the fuel energy input and the energy gain of the working fluid.

Thus it is possible to have two distinctly different calorific values for fuels containing hydrogen - the gross calorific value (GCV) and the net calorific value (NCV). The GCV assumes that the water vapour from combustion has been condensed to a liquid, while the NCV does not assume condensation of the vapour.

Energy Input

= Coal Flow Rate x G.C.V.

Energy Output = Steam Flow Rate x Enthalpy Gain Efficiency = Energy Output Efficiency = Efficiency = Energy Input

Those in favour of the use of the lower Calorific Value argue that practical power cycles are not able to use the energy contained in the vapour, while those who prefer the Gross Calorific Value feel that this is a problem of the cycle rather than one of the fuel.

Note that:1. The power requirements of the boiler auxiliaries (e.g. fans and pumps) are not normally included in this calculation. 2. The accurate measurement of steam flow at high temperatures and pressures is difficult and it is thus more common to measure the flow of feedwater to the boiler.

By convention, it is common to use the Gross Calorific Value in boiler calculations. Coal Analysis

DIRECT METHOD EXAMPLE Customary practice in reporting the components of a coal is to use two different analyses, known as

Gross Calorific Value of the Coal = 27,32 MJ/kg

72

Ultimate Analysis of the Coal (% by mass)

Measured Values Coal Flow Feedwater Flow Feedwater Temperature Superheater outlet temperature Superheater Outlet pressure

Carbon Hydrogen Oxygen Ash Moisture – Inherent -Superficial Nitrogen Sulphur

3,3kg/s 30,4kg/s 175,4ºC 450,0ºC 4,00 Mpa

Energy Input = Coal Flow Rate x Gross Calorific Value = 3,3 x 27 320 = 90 156 kJ/s (Kw)

Gross Calorific Value

= = =

27,32MJ/kg

Flue Gas Analysis

Energy Output = Steam Flow Rate x Enthalpy Gain = 30,4 x (3330 - 743) kJ/s = 78 644,8 kJ/s Efficiency

64,6% 4,0% 7,0% 14,4% 3,4% 4,1% 1,0% 1,5% 100%

CO2 CO O2 N2

Energy Output Energy Output 78 644,8 x 100% 90 156,0 87,32 %

14,9% 0,4% 4,4% 80,3% 100,0%

Measured Values Carbon in ash Flue Gas Outlet temperature Ambient Dry Bulb Air Temperature Ambient Wet Bulb Air Temperature

The Indirect Method of Boiler Efficiency Calculation In order to calculate the boiler efficiency via the indirect route, all the energy losses that occur within the boiler must be established.These losses are conveniently related to the amount of fuel burnt (i.e. kilojoules per kilogram of coal consumed or to the amount of energy supplied (i.e. losses as a percentage of the energy content of the fuel). In this way it is easy to compare the performance of differently rated boilers.

12,87% 139,0 ˚C 30,0 ˚C 22,0 ˚C

The various losses associated with the operation of a boiler are discussed below. Energy Loss Due to Unburned Carbon Small amounts of carbon will be left in the ash and this constitutes a loss of potential heat in the fuel. To assess these heat losses, samples of ash must be analysed for carbon content. The quantity of ash produced per unit of fuel must also be known. With this information, the unburned carbon loss can be expressed as:-

For the purposes of illustration, typical values, which would have been obtained from a boiler efficiency test, are included below and these values are used to demonstrate the equations derived for the boiler losses.

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mg

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 total ash quantity.

cp

Tg and

It will be seen from the above formula that the losses are directly proportional to the gas flow and to the temperature difference of the gas across the boiler. Consequently, any increase in the excess air quantity will increase the magnitude of this loss.

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 = 626,78 or = x 100% or = 27 320 = 2,29% Mass of unburned carbon = = =

On the other hand, a reduction in the temperature difference will reduce the loss. To achieve this reduction, economizers and air heaters are used to reduce the exhaust gas temperature, while the inlet air suction is often situated in the warm region of the power station, immediately below the roof.

mash Ca 0,144 x 0,1287 0,0185 kg carbon/kg fuel

The above equation relates the Dry Flue Gas Loss to the mass flow of gas.To calculate the efficiency, it is necessary to relate this loss to the mass of fuel burned. In other words, we need to know how much gas one kilogram of fuel will generate.

Energy Loss due to the Dry Flue Gas There is an energy loss associated with the fact that the nitrogen, which enters the boiler as a constituent of the combustion air, leaves the boiler at a higher temperature. Additionally, the gaseous combustion products leave the boiler at an elevated temperature. This energy is lost to the system.

In the ideal case: Carbon in Fuel

Process

Carbon in flue gas

All the carbon in the fuel is converted in the boiler into gas which contains carbon, in the form of C02.Therefore over a given period of time:-

This is the greatest boiler loss in a correctly operated system and can be calculated with the following formula: Gfd = mg cp (Tg – Ta)

Ta

= Mass Flow of Gas (kg gas per kg of fuel) = Specific Heat of the Gas. The approximate value for dry air can be used (1,005kJ/kg ºC) = Temperature of the gas leaving the boiler (ºC) = Temperature of the gas entering the boiler (ºC)

Carbonin = % Carbon in the fuel x mass of fuel Carbonout = % Carbon in the flue gas x mass of flue gas

…..(2)

Since carbon cannot be destroyed, Carbonin = Carbonout

where Qfd = Dry Flue Gas Loss (kilojoules/kg fuel)

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 % Carbon in fuel x mass of fuel = % Carbon in flue gas x mass of flue gas or Mass of flue gas = % Carbon in fuel Mass of fuel % Carbon in flue gas

The mass of carbon in 1 kg of dry flue gas = 12 CO2 + 12 CO …(4) = = 44 CO2 + 32O2 + 28CO + 28N2

In other words:-

…(4) …(4)

where C02, CO, O2 and N2 refer to the percentage volumes of the components in the flue gas.

Kilograms Dry Flue Gas Kilograms Fuel = % by weight of carbon in the fuel % by weight of carbon in dry flue gas

Substituting equation (4) into equation (3), it is possible to calculate the kilograms of dry flue gas produced for each kilogram of fuel burnt.

As shown above, not all the carbon is burnt and some of it remains in the ash.Therefore instead of referring to the weight of carbon in the fuel, the weight of carbon consumed should be used and the above equation becomes:-

Multiplying this answer by equation (2) (the dry flue gas loss in terms of flue gas flow), enables the Dry Gas Loss per mass of fuel burnt to be established. EXAMPLE 2

Kilograms Dry Flue Gas Kilograms Fuel = % by weight of carbon consumed % by weight of carbon in dry flue gas

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

A further correction is required to improve the accuracy of this equation. At the moment the equation ignores the fact that sulphur burns to SO2. The easiest way of including the sulphur in the fuel is to add the “carbon equivalent” of sulphur to the carbon consumed. It can be proved that as far as the production of flue gas is concerned, sulphur produces less gas than carbon in the ratio of 12 to 32 (the molecular weights of the two elements concerned).The above equation then becomes:-

Mass of carbon in 1 kg of fuel = 0,646 kg Calculated mass of unburnt carbon = 0,0185 kg Therefore mass of carbon consumed = 0,6275 kg Carbon Equivalent of Sulphur = Percentage sulphur x 12 = Percentage sulphur x = Percentage sulphur x 32 = 1,5 x 12 100 32 = 0,0056 Mass of Dry Gas per kg of Fuel

Kilograms Dry Flue Gas Kilograms Fuel = % carbon consumed + sulphur x 12/32 = % by weight of carbon in dry flue gas …(3) The next problem is to establish the percentage by weight of carbon in dry flue gas. Without going into the proof, it can be shown using Avogadro’s law (which implies that masses of equal volumes of gases will be proportional to their molecular weights) that:-

= Carbon Consumed + Carbon Equivalent of Sulphur Carbon in the Flue Gas

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EXAMPLE 3

= 0,6275 + 0,0056 0,0601 = 10,53 kg dry gas/kg fuel But 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 %

Qcm = mw [cpw (Tsat – Ta) + hfg + cps (Tg – Tsat)] Moisture in the fuel = (3,4 + 4,1) 100 = 0,075 kg moisture/kg fuel Qcm = 0.075 x [4,18 x (100-30) + 2 258 + 2,01 x (139-100)) = 197,17 kJ/kg fuel or = 19717 x 100% 27320 = 0,72 %

Energy Loss Due to Evaporating and Superheating the Moisture in the Fuel Moisture entering the boiler with the fuel leaves as a superheated vapour. This moisture loss is made up of the sensible heat to bring the moisture to boiling point, the latent heat of evaporation of the moisture, and the superheat required to bring this steam to the temperature of the exhaust gas.This loss can be expressed in the following

Energy Loss Due to Evaporating and Superheating the Moisture Formed by the Combustion of Hydrogen

Qcm = mw [cpw (Tsat – Ta) + hfg + cps (Tg – Tsat)] …(5)

The combustion of hydrogen causes a heat loss because the product of combustion is water. This water is converted to steam in the boiler and this carries away heat, particularly because of its latent heat content.

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 the temperature range of interest. Tsat = The saturation temperature at which the water evaporates. For the sake of simplicity, this temperature is assumed to be 1OOºC. hfg = The latent heat of evaporation of water at 1000C and 1 bar. (2 258 kJ/kgºC). cps = Specific heat of steam (kJ/kgºC). A value of 2,01 corresponding to a temperature of 100ºC can be used. Tg = Temperature of the gas leaving the boiler (ºC) Ta = Temperature of the gas entering the boiler (ºC)

The chemical equation for the reaction between hydrogen and oxygen is:2H2 + O2 = 2 H2O Considering molecular weights; 4 + 32 = 36 In other words, 1 kg of hydrogen will produce 9 kg of water. The equation for the hydrogen loss can therefore 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 the temperature range of interest.

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volumetric percentage of carbon monoxide in the flue gas, as in the case of the dry gas losses, it is necessary to relate CO to the mass of fuel burnt. The energy loss can then be calculated by multiplying the mass of CO by its calorific value (10143 kJ/kg)

Tsat = The saturation temperature at which the water evaporates. For the sake of simplicity, this temperature is assumed to be 1OOºC. hfg = The latent heat of evaporation of water at 100ºC and 1 bar. (2 258 kJ/kgºC). cps = Specific heat of steam (kJ/kgºC). A value of 2,01 corresponding to a temperature of 1OOºC can be used. Tg = Temperature of the gas leaving the boiler (ºC) Ta = Temperature of the gas entering the boiler (ºC)

In equation (3), the mass of dry flue gas was related to the mass of fuel burnt. i.e. Kg Dry Flue Gas Kilograms 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:-

EXAMPLE 4 Hydrogen in the fuel

=

K Dry Flue Gas Kilograms Fuel = A = Weight of C in dry flue gas Weight of dry flue gas

4,0 %

Moisture produced by combustion of H2 as % of fuel = 4,0 x 9 = 36% or 0,36 kg moisture/kg fuel Qhf = 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%

…(7)

Using Avogadro’s law once again, it can be shown that the ratio of CO to the weight of dry flue gas is:=

28CO weight of dry flue gas

Multiplying both sides of equation (7) by this ratio yields:-

Energy Loss Due to Incomplete Combustion Left-Hand Side Products formed by incomplete combustion could be mixed with oxygen and burned again with a further release of energy. Such products include CO, H2, and various hydrocarbons and are generally only found in the flue gases from older chain-grate boilers. Carbon monoxide is the only gas whose concentration can be determined conveniently in a power plant test.

Kg Dry Flue Gas x Kilograms CO = Kilograms CO Kilograms Fuel Kg Dry Flue Gas Kilograms Fuel Right-Hand Side = A x weight of dry flue gas x 28CO Weight of C in dry flue gas weight of dry flue gas =

While it is relatively easy to determine the

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A x 28CO Weight of C in dry flue gas

Hence: Kilograms CO = (% carbon consumed + % sulphur x 12/32) x 28 CO Kilograms Fuel 12CO2 + 12CO and Multiplying this value by the calorific value of carbon monoxide (10 143 kJ/kg) loss due to carbon monoxide per kilogram of fuel burnt.

cp = Specific Heat of the Vapour (kJ/kgºC). A value of 2,01, corresponding to a temperature of 100ºC can be used. Tg = Temperature of the gas leaving the boiler (ºC) Ta = Temperature of the gas entering the boiler (ºC)

To relate this loss to the mass of coal burned, the moisture content of the combustion air and the amount of air supplied per unit mass of coal burned must be known.

EXAMPLE 5 The percentage of carbon monoxide in 1 kg of fuel

The mass of vapour that air contains can be obtained from psychrometric charts and typical values are included below:

= (% carbon consumed + % sulphur x 12/32) x 28 CO 12CO2 +12CO = (62,75 + 1,5 x 12/32) x 28 x 0,4 12 x 14,9 + 12 x 0,4 = 3,86 % or = 0,0386 kg CO/kg fuel Calorific Value of CO = 10 143 kJ/kg CO Heat Loss/kg fuel = 10 143 x 0,0386 = 391,74 kJ/kg fuel or = 391 74 x 100% 27320 = 1,43 %

Dry-Bulb

Wet Bulb

Temp ºC

Temp ºC

Relative Humidity (%)

20 20 30 40

20 14 22 30

100 50 50 50

Kilogram Water per kilogram Dry Air 0,016 0,008 0,014 0,024

The materials entering a boiler for combustion purposes are the fuel and the combustion air.The total mass of the products of combustion must therefore equal the sum of the mass of the fuel and air.The products of combustion consist of wet flue gas and ash. Hence:-

Energy Loss Due to Superheating Vapour in the Combustion 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 be included as a boiler loss.

Mass of (Fuel + Air) = Mass of (Wet Flue Gas + Ash)

This loss is given by the following formula:-

or

Qfm = cp (Tg – Ta) (9) Where Qfm = Air Vapour Loss ( k i l o j o u l e s / k g vapour)

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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Combustion Air Moisture Loss

the dry gases plus the moisture contained in the fuel and the moisture from the combustion of hydrogen.

= 10,11 x 3,07 kJ/kg fuel 31,03 kJ/kg fuel or = 31,03 x 100 % 27320 0,11 % Radiation and Unaccounted Losses

EXAMPLE 6 From psychrometric charts, at 30ºC dry bulb temperature and 22ºC wet bulb temperature, the relative humidity is 50% and the moisture content of the air is 0,014 kg/kg. Qfm

The remaining heat losses from a boiler consist of the loss of heat by radiation from the boiler casting into the surrounding boiler house. Additionally, the losses associated with the incomplete combustion of the fuel to hydrogen and hydrocarbons in the flue gas are included here. Further, there can be a sensible heat loss from the hot ash which leaves the boiler.

= = = or =

cp(Tg – Ta) 2,01 x (139 – 30) 219,09kJ/kg vapour 219,09 x 0,014kJ/kg of dry air entering boiler = 3,07kJ/kg

In a relatively small boiler, with a capacity of 10 MW, the radiation and unaccounted losses could amount to between 1% and 2% of the gross calorific value of the fuel, while in a 500 MW boiler, values of between 0,2% and 1 % are typical.

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)

Radiation and unaccounted boiler losses. Lower curve for radiation only is based on data in the American power test code. The unaccounted losses are primarily due to moisture in the combustion air and sensible heat in the refuse. They could be larger particularly if unburnt gases are present but not detected.

–––––– Total Wet Gas/kg fuel Total Ash Content Total fuel burnt

= 10,97 kg/kg 0,144 kg/kg (from Analysis) 1 kg (by definition)

Heat Balance Having established the magnitude of all the losses mentioned above, a simple heat balance will give the efficiency of the boiler. The efficiency is the difference between the energy input to the boiler and the heat losses calculated.

Therefore Mass of Air = 10,97 + 0,144 – 1 = 31,03 kJ/kg fuel

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BOILER HEAT BALANCE 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)

EXAMPLE SOLUTION

86,77%

Unburnt Carbon Loss

Ultimate Analysis of the Coal (% by mass) Carbon Hydrogen Oxygen Ash Moisture – Inherent - Superficial Nitrogen Sulphur

____% ____% ____% ____% ____% ____% ____% ____% 100%

Gross Calorific Value

____ MJ/kg

Mass of unburned carbon = massash % x Carbonash % 100 100 = ____ x ____ 100 100 = ____ kg carbon/kg fuel Unburnt Carbon Loss = kg C/kg Fuel x CVcarbon _____ x 33 820 kJ/kg fuel or = Carbon Loss x 100% GCV of fuel = ______ x 100 = ____%

Flue Gas Analysis CO2 CO O2 N2

____% ____% ____% ____% 100,0%

Dry Flue Gas Loss

The mass of carbon in 1 kg of flue gas

(or by difference)

= 12 CO2% + 12 CO% 44 CO2% + 32O2% + 28 CO% + 28 N2% = 12 x + 12 44 x ____ + 32 x ____ + 28 x ____ + 28 x ____ = ______ kg carbon / kg flue gas

Measured Values Carbon in ash Flue Gas Outlet temperature Ambient Dry Bulb Air Temperature Ambient Wet Bulb Air Temperature

____% ____ºC ____ºC ____ºC

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Moisture produced by combustion of H2 as % of fuel = _____ x 9 = _____% or _____ kg moisture/kg fuel

Mass of carbon in 1 kg of fuel = ____kg Calculated mass of unburnt carbon = ____ kg Therefore mass of carbon consumed = ____kg Carbon Equivalent of Sulphur = Percentage sulphur x 12/32

Qhf

= ____ x 12 100 32 = ____kg or Mass of Dry Gas per kg of Fuel = Carbon Consumed + Carbon Equivalent of Sulphur Carbon in the Flue Gas = + _______ = ____ kg dry gas / kg fuel

Incomplete Combustion The percentage of carbon monoxide in 1 kg of fuel = (% carbon consumed + % sulphur x 12/32) x 28 CO 12CO2 + 12CO = ( + x 12/32) x 28 x 12 x ____ + 12 x ____ = ____ % or = ____ kg CO/kg fuel Calorific Value of CO = 10 143 kJ/kg CO Heat Loss/kg fuel = 10 143 x _____ = ______ kJ/kg fuel or = _____ x 100 % ___ = ____ %

But Qfd = massgas x cp x (Tgas – Tambient air)

or

= ____ x 1,005 x (____ - ____) = ________kJ / kg fuel = ______ x 100 % ____ = _____%

Moisture in the Fuel Qcm = mw [cpw (Tsat – Ta) + hfg + cps (Tg – Tsat)] Moisture in the fuel = (

Qcm

= = or = =

%+ 100

%)

Moisture in the Combustion Air From psychrometric charts, at _____ dry bulb temperature and ______ wet bulb temperature, relative humidity is ___%and the moisture content of the air is _____ kg/kg.

= _____ kg moisture/kg fuel _____ x [4,18 x (l00 - ___) + 2 258 + 2,01 x (___ - l00)] ______ kJ/kg fuel _______ x l00% ____ ____%

Qfm

Hydrogen Loss Hydrogen in the fuel

= 9 mh [cpw (Tsat – Ta) + hfg + cps (Tg – Tsat)] = _____x [4,18 x (l00 - ___) + 2 258 + 2,01 x (___ - l00)] = ______ kJ/kg fuel = _____ x 100 % ___ = ______ %

or =

_____%

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= = = =

cp (Tg – Ta) 2,01 x (___ - ___) _____ kJ/kg vapour ____ x ____ kJ/kg of dry air entering boiler = ____kJ/kg

Therefore Mass of Air = _____ + _____ -1 = _____ kg dry air/kg fuel Combustion Air Moisture Loss = _____ x _____ k J / k g fuel = _____ kJ/kg fuel or = _____ x 100 % ___ = ____ %

Mass of Air Mass of dry gas/kg fuel = Mass of (Wet Flue Gas + Ash - Fuel) Moisture in fuel = _____ kg/kg Moisture from H2 = _____ kg/kg Total Wet Gas/kg fuel = _____ Total Ash Content = _____ Total fuel burnt

= 1

kg/kg kg/kg (from Analysis) kg (by definition)

BOILER HEAT BALANCE 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)

–––

•••••••••

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furnace efficiency test

•••••••••••••• The following gives a ‘direct method’ methodology for calculating the efficiency of a heating furnace. It is more simplified than the boiler example given above due to the range of different furnace configurations, where constant heating and cooling make it difficult to calculate the ‘non-steady’ losses explicitly.

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 final solid temperature Tfs and the starting liquid temperature,Tol are both the melting temperature, Tm. The overall energy requirement to heat from solid at temperature Tos to liquid at Tfl is:

The energy required to heat any material is given by the mass, M, multiplied by the specific heat, Cp, multiplied by the temperature rise. The energy required to heat a solid with specific heat Cps from Tos to some final temperature Tfs is therefore:

Energy = M Cps (Tm – Tos) + Lm + Cpl (Tfl – Tm) Energy = Energy = e

energy to heat solid = M Cps (Tfs - Tos)

m m m

M is a common term and a graph of energy vs. production is expected to be a straight line of slope, m, where:

The energy required to melt a material at its melting temperature is the mass, M, multiplied by the latent heat of melting, Lm: energy

to melt material at melting temperature

A value of m can be determined from the graph. Cps,Tm, Lm and Cpl are characteristics of the material and can be looked up in reference books. Tos and Tfl, the initial and final temperatures, are process parameters of which management should already be aware.

= MLm

The energy required to raise the temperature of a liquid is analogous to that of the solid and is the mass, M, multiplied by the specific heat of the liquid, Cpl, multiplied by the temperature rise from the starting temperature, Tol, to the final liquid temperature,Tfl. So: energy

melt to final temperature

= Cps (Tm – Tos) + Lm + Cpl (Tfl – Tm) = = e

Everything in this expression except the efficiency, e, is known. The slope of the line e is 2.585 Gj/te. Take the pouring temperature to be 730ºC. The specific heat capacity of aluminium from ambient temperature to the melting point at 661ºC is 1.061 kJ/kg/º0 and for the liquid is 1.177 kJ/kg/ºC. The latent heat of melting is 396 kJ/kg.

= M CPl (Tfl - Tol)

Calculating the process efficiency: Energy is delivered at some efficiency which, because this is a straight line, clearly is not dependent on the amount of material being processed and can be expressed as a constant, e.

slope = 1.06 x (661 – 25) + 396 + 1.177 )760 – 661) = 1,152 slope = 1.06 x (661 – 25) + 396 + 1.177 )760 – 661) = 1,152 slope = e e The efficiency of the furnace is therefore:

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e = 1,152 e = 1,152 = 45% e = 2,585

constituent elements in the proportions of its chemical formula.

This level of efficiency is quite good for a gas-fired furnace in this application.

Note: Very precise information (which is usually the best to use) on heat capacities, and the temperature ranges over which they are valid, is often provided in reference texts as the numerical values of coefficients A. B. C and D in an equation of the form:

Selecting specific heat data It is important to select the right data on specific heats. Specific heats vary with temperature and, where not specified, tend to be quoted in reference texts at, or around, 25ºC (298ºK). This can be rather misleading - particularly in high temperature processes. Heat capacity is often quoted in reference texts as the molar heat capacity, which is the energy required to raise one gram-molecular weight (the molecular weight expressed in grams) by 1ºC. So, to convert this to a kg basis, divide by the molecular weight and multiply by 1,000. To calculate the molecular weight of a material, add the atomic weights of its

Cp = A + BT + C + DT2 Cp = A + BT + C + DT22 Cp = A + BT + T2 + DT For some materials it may be necessary to use several such formulae to cover the range of temperatures required. For comprehensive information on specific heats, latent heats of fusion and evaporation. Specialist textbooks on the processes in use in specific industries usually also provide this information.

•••••••••

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•••••••••••••• SOURCES OF FURTHER INFORMATION

For the latest news in energy efficiency technology: “Energy Management News” is a free newsletter issued by the ERI, which contains information on the latest developments in energy efficiency in Southern Africa and details of forthcoming energy efficiency events. Copies can be obtained from: The Energy Research Institute Department of Mechanical Engineering University of Cape Town Rondebosch 7700 Cape Town South Africa Tel No: (+27 21) 650 3892 Fax No: (+27 21) 686 4838 Email: [email protected]

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