A Project Report On PROBLEMS IN BOILER LIKE EFFIENCY,MAINTENANCE AND SAFETY. Submitted in partial fulfillment of the requirements for the degree of Bachelor of Engineering Submitted by Patel Dhaval J (Enr. No. 080350119034, 7th Sem, ME.) Patel Hardik N (Enr. No. 080350119035, 7th Sem, ME.) Patel Nishit K (Enr. No. 080350119038, 7th Sem, ME.) under the guidance of Internal Guide External GuideAsst. Prof. H.C. Badrakia Mr. Haridas Krisnan (M. E. Dept.) Submitted to Noble Group of Institutions-Junagadh
Mechanical Engineering Department Year 2010-2011
Noble Group of institutionsJunagadh CERTIFICATE This is to Certify that Mr. / Miss ………………………………….Enrollment No ………………… of B.E. ……… Semester of Mechanical Engineering has satisfactorily completed his/her project work for partial fulfillment for the duration of …………………. to ………………….. Guided By Head of Department (Mr. H.C. Badrakia) (Mr. V.T. Shekhada) ( Mechanical Engg. Department) Date:-20/10/2011
Noble Group of institutionsJunagadh CERTIFICATE This is to Certify that Mr. / Miss ………………………………….Enrollment No ………………… of B.E. ……… Semester of Mechanical Engineering has satisfactorily completed his/her project work for partial fulfillment for the duration of …………………. to ………………….. Guided By Head of Department (Mr. H.C. Badrakia) (Mr. V.T. Shekhada) ( Mechanical Engg. Department) Date:-20/10/2011
Noble Group of institutionsJunagadh CERTIFICATE This is to Certify that Mr. / Miss ………………………………….Enrollment No ………………… of B.E. ……… Semester of Mechanical Engineering has satisfactorily completed his/her project work for partial fulfillment for the duration of …………………. to ………………….. Guided By Head of Department (Mr. H.C. Badrakia) (Mr. V.T. Shekhada) ( Mechanical Engg. Department) Date:-20/10/2011
Acknowledgement Many people have contributed to this work and have made it possible for us to escapewith what little sanity remains. I would like to thank Mr. Hiral badrakia, our advisor for theduration, for supporting us during our time. He has provided direction and opinion grounded inthe reality that we all too often allow to pass by the wayside in our quest for solutions. He hasalso been a friend and mentor and We sincerely hope we find opportunities in the future to worktogether once again. We would also like to extend my thanks to Mr. Haridas Krisnan, the manwho has taught us the importance of written and oral communication skills in the engineeringprofession. Further, his outlook on life has been inspiring and at times, frightening. He, aboveall, exemplifies the importance maintaining a realistic opinion of the importance of your work; itkeeps you honest.
PREFACE` The mechanical engineering is well structured and integrated course of engineeringstudies. The main objective of Industrial Define Problem (IDP) is to develop skill in student bysupplement to the theoretical study. Industrial training helps to gain real life knowledge about theindustrial environment, manufacturing practices and to develop skill about industrial problem. In every professional course, IDP is an important factor. Professors give us theoreticalknowledge of various subjects in the college but we are practically exposed of such subjectswhen we get the project in the organization. It is only the project through which I come to knowthat what an industry is and how it works and how to problem can be solved. I can learn aboutvarious departmental operations being performed in the industry, which would, in return, helpme in the future when I will enter the practical field. During this whole project I got a lot of experience and came to know about themanufacturing process and industrial problems in real that how it differs from those oftheoretical knowledge and the practically in the real life. In todays globalize world, where cutthroat competition is prevailing in the market,theoretical knowledge is not sufficient. Beside this one need to have practical knowledge, whichwould help an individual in my carrier activities and it is true that “Experience is best teacher”. Patel Hardik Patel Dhaval Patel Nishit
INDEX1. INTRODUCTION 1.1 BOILER SPECIFICATION 1.2 BOILER SYSTEM2. BOILER TYPES AND CLASSIFICATIONS3. FEATURE OF PACKAGE BOILER 3.1 CHAIN GRATE FOR TRAVELLING GRATE STROKER BOILER.4. DEFINING BOILER EFFICIENCY 4.1 BOILER TERMINOLOGY5. METHODS OF FINDING EFFICIENCY OF THE BOILER 5.1 EQUIVALENT EVAPORATION 5.2 FACTOROF EQUIVALENT EVAPORATION 5.3 INDIRECT METHOD 5.4 FACTOR AFFECTING EFFICIENCYS 6. IMPROVING ENERGY EFFICIENCY OF BOILER SYSTEM 6.1 COMBUSTION EFFICIENCY 6.2 EXCESS AIR V/S BOILER EFFICIENCY 6.3 COMBUSTION EFFICIENCY INDICATOR 6.4 COMBUSTION GET CONCENTRATIONS AT PERCENT OF THE THEREOTICAL COMBUSTION AIR 6.5 FLUE GAS ANALYSIS- WHAT TO MEASURE O2 OR CO2 6.6 APPROACH TO OPTIMUM COMBUSTION CONTROL 6.7 OXYGEN TRIM SYSTEM 6.8 NEGATIVE EFFECTS OF IMPROPER COMBUSTION 6.9 KEEPING BOILER CLEAN FROM SOOT 6.10 ENERGY LOSS DUE TO IMPROPER DE AERATION OF BOILER FEEDWATER 7. BLOWDOWN WATER………………………………… 7.1 EFFECT OF INSUFFICIENT OF EXCESSIVE BLOWDOWN 7.2 CHLORIDE TEST 7.3 METHODS FOR CONTROLLING BLOWDOWN 7.4 FLASH STEAM RECOVERY 7.5 OPTIMUM PIPE SIZING 7.6 PROPER INSULATION OF STEAM PIPE 7.7 STEAM USE IN HEATING 8. BOILER TECHNOLOGY 8.1 CURRENT TECHNOLOGY 9. IMPROOVEMENT OF BOILER EFFICIENCY 9.1 REDUCING LOSS DUE TO UNBURNT FUEL 9.2 REDUCING DRY GAS LOSS 9.3 REDUCING LOSS DUE TO FUEL MOISTURE 9.4 EMERGING BOILER TECHNOLOGY 10. BOILER OPERATION AND MAINTANANCE 10.1 MAINTANACE LOGIC BASIS
10.2 NORMAL OPERATING WATER LEVEL 10.3 BLOWDOWN 10.4 LOW WATER FUEL CUT OUT 10.5 BOILER WATER TREATMENT 10.6 MAINTANANCE OF STEAM PIPES 10.7 CHARACTERISTICS OF STEAM STRAP FAILURE11. MAIINTAINING BOILER SAFETY 11.1 SAFETY 11.2 BOILER FAILURE 11.3 POOR FEED WATER QUALITY 11.4 IMPROPER BLOWDOWN 11.5 STEAM BOILER FAILURE 11.6 COMMON CAUSESS OF FUEL EXPLOSION 11.7 STEAM BOILER FAILURE 11.8 BOILER SAFETY OPERATION AND MAINTANACE AND PRACTISES12. CONCLUSION13. REFERENCE
1. Introduction Boiler is A an enclosed vessel that provides a means for combustion heat to be transferred intowater until it becomes heated water or steam. The hot water or steam under pressure is thenusable for transferring the heat to a process. Water is a useful and cheap medium fortransferring heat to a process. When water is boiled into steam its volume increases about 1,600times, producing a force that is almost as explosive as gunpowder. This causes the boiler to beextremely dangerous equipment that must be treated with utmost care.The process of heating a liquid until it reaches its gaseous state is called evaporation. Heat istransferred from one body to another by means of (1) radiation, which is the transfer of heatfrom a hot body to a cold body without a conveying medium, (2) convection, the transfer ofheat by a conveying medium, such as air or water and (3) conduction, transfer of heat by actualphysical contact, molecule to molecule.Boiler SpecificationThe heating surface is any part of the boiler metal that has hot gases of combustion on one sideand water on the other. Any part of the boiler metal that actually contributes to making steam isheating surface. The amount of heating surface of a boiler is expressed in square meters. Thelarger the heating surface a boiler has, the more efficient it becomes. The quantity of the steamproduced is indicated in tons of water evaporated to steam per hour. Maximum continuousrating is the hourly evaporation that can be maintained for 24 hours. F & A means the amount o oof steam generated from water at 100 C to saturated steam at 100 CBOILER SYSTEMSThe boiler system comprises of: feed water system, steam system and fuel system. The feedwater system provides water to the boiler and regulates it automatically to meet the steamdemand. Various valves provide access for maintenance and repair. The steam system collectsand controls the steam produced in the boiler. Steam is directed through a piping system to thepoint of use. Throughout the system, steam pressure is regulated using valves and checked withsteam pressure gauges. The fuel system includes all equipment used to provide fuel to generatethe necessary heat. The equipment required in the fuel system depends on the type of fuel usedin the system.The water supplied to the boiler that is converted into steam is called feed water. The twosources of feed water are: (1) Condensate or condensed steam returned from the processes and(2) Makeup water (treated raw water) which must come from outside the boiler room and plantprocesses. For higher boiler efficiencies, the feed water is preheated by economizer, using thewaste heat in the flue gas.
2. Boiler Types and Classifications There are virtually infinite numbers of boiler designs but generally they fit into one of two categories: Fire tube or "fire in tube" boilers; contain long steel tubes through which the hot gasses from a furnace pass and around which the water to be converted to steam circulates. Fire tube boilers, typically have a lower initial cost, are more fuel efficient and easier to operate, but they are 2 limited generally to capacities of 25 tons/hr and pressures of 17.5 kg/cm . Water tube or "water in tube" boilers in which the conditions are reversed with the water passing through the tubes and the hot gasses passing outside the tubes . These boilers can be of single- or multiple-drum type. These boilers can be built to any steam capacities and pressures, and have higher efficiencies than fire tube boilers. Packaged Boiler: The packaged boiler is so called because it comes as a complete package. Once delivered to site, it requires only the steam, water pipe work, fuel supply and electrical connections to be made for it to become operational. Package boilers are generally of shell type with fire tube design so as to achieve high heat transfer rates by both radiation and convectionWater Tube Boiler
3. Features of package boilers Small combustion space and high heat release rate resulting in faster evaporation. Large number of small diameter tubes leading to good convective heat transfer. Forced or induced draft systems resulting in good combustion efficiency. Number of passes resulting in better overall heat transfer. Higher thermal efficiency levels compared with other boilers. These boilers are classified based on 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 of this class is a three-pass unit with two sets of fire-tubes and with the exhaust gases exiting through the rear of the boiler.Stoker Fired Boiler:Stokers are classified according to the method of feeding fuel to the furnace and by the type ofgrate. The main classifications are: 1. Chain-grate or traveling-grate stoker 2. Spreader stoker Chain-Grate or Traveling-Grate Stoker BoilerCoal is fed onto one end of a moving steel chain grate. As grate moves along the length of thefurnace, the coal burns before dropping off at the end as ash. Some degree of skill is required,particularly when setting up the grate, air dampers and baffles, to ensure clean combustionleaving minimum of unburnt carbon in the ash.The coal-feed hopper runs along the entire coal-feed end of the furnace. A coal grate is used tocontrol the rate at which coal is fed into the furnace, and to control the thickness of the coal bedand speed of the grate. Coal must be uniform in size, as large lumps will not burn out completelyby the time they reach the end of the grate. As the bed thickness decreases from coal-feed end torear end, different amounts of air are required- more quantity at coal-feed end and less at rear end
Spreader Stoker Boiler Spreader stokers utilize a combination of suspension burning and grate burning. The coal is continually fed into the furnace above a burning bed of coal. The coal fines are burned in suspension; the larger particles fall to the grate, where they are burned in a thin, fast-burning coal bed. This method of firing provides good flexibility to meet load fluctuations. Pulverized Fuel Boiler Most coal-fired power station boilers use pulverized coal, and many of the larger industrial water-tube boilers also use this pulverized fuel. This technology is well developed, and there are thousands of units around the world, accounting for well over 90% of coal-fired capacity. The coal is ground (pulverised) to a fine powder, so that less than 2% is +300 micro metre (μm) and 70-75% is below 75 microns, for a bituminous coal. It should be noted that too fine a powder is wasteful of grinding mill power. On the other hand, too coarse a powder does not burn completely in the combustion chamber and results in higher unburnt losses. The pulverised coal is blown with part of the combustion air into the boiler plant through a series of burner nozzles. Secondary and tertiary air may also be added. Combustion takes place at temperatures from 1300-1700°C, depending largely on coal grade. Particle residence time in the boiler is typically 2 to 5 seconds, and the particles must be small enough for complete combustion to have taken place during this time. This system has many advantages such as ability to fire varying quality of coal, quick responses to changes in load, use of high pre-heat air temperatures etc. One of the most popular systems for firing pulverized coal is the tangential firing using four burners corner to corner to create a fireball at the center of the furnace
4. Defining Boiler EfficiencyBoiler efficiency is defined as the heat added to the working fluid expressed as apercentage of the heat in the fuel being burnt. Boiler efficiency to the greater extentdepends on the skill of designing but there is no fundamental reason for any difference inefficiency between a high pressure or low pressure boiler. Large boilers generally wouldbe expected to be more efficient particularly due to design improvements.A typical boiler will consume many times the initial capital expense in fuel usageannually. Consequently, a difference of just a few percentage points in boiler efficiency44between units can translate into substantial savings. There are listing some of the design requirement of boilers:a. Should be able to produce at required parameters over an appreciable range of
loading.b. Compatible with feed water conditions which change with the turbine load.c. Capable of following changes in demand for steam without excessive pressure swing.This Efficiency Facts Booklet is designed to clearly define boiler efficiency. It will alsogive you the background in efficiency needed to ask the key questions when evaluatingefficiency data, and provide you with the tools necessary to accurately compare fuelusage of boiler products, specifically fire tube type boilers. Simplified Boiler efficiency Boiler TerminologyMCR: Steam boilers rated output is also usually defined as MCR (Maximum ContinuousRating). This is the maximum evaporation rate that can be sustained for 24 hours andmay be less than a shorter duration maximum rating.Efficiency: In the boiler industry there are four common definitions of efficiency:Combustion efficiencyCombustion efficiency is the effectiveness of the burner only and relates to its ability to
completely burn the fuel. The boiler has little bearing on combustion efficiency. A well designedburner will operate with as little as 15 to 20% excess air, while converting allcombustibles in the fuel to useful energy.Combustion efficiency is an indication of the burner‟s ability to burn fuel. The amount ofunburned fuel and excess air in the exhaust are used to assess a burner‟s combustion efficiency.Burners resulting in low levels of unburned fuel while operating at low excess air levels areconsidered efficient. Well designed burners firing gaseous and liquid fuels operate at excess airlevels of 15% and result in negligible unburned fuel. By operating at only 15% excess air, lessheat from the combustion process is being used to heat excess air, which increases the availableheat for the load. Combustion efficiency is not the same for all fuels and, generally, gaseous andliquid fuels burn more efficiently than solid fuels.Thermal efficiencyThermal efficiency is the effectiveness of the heat transfer in a boiler. It does not takeinto account boiler radiation and convection losses – for example from the boiler shellwater column piping etc.Thermal efficiency is a measure of the effectiveness of the heat exchanger of the boiler.It measures the ability of the exchanger to transfer heat from the combustion process tothe water or steam in the boiler. Because thermal efficiency is solely a measurement ofthe effectiveness of the heat exchanger of the boiler, it does not account for radiation andconvection losses due to the boiler‟s shell, water column, or other components. Sincethermal efficiency does not account for radiation and convection losses, it is not a trueindication of the boilers fuel usage and should not be used in economic evaluations.Boiler efficiencyThe term boiler efficiency is often substituted for combustion or thermal efficiency. Trueboiler efficiency is the measure of fuel to steam efficiency.The term “boiler efficiency” is often substituted for thermal efficiency or fuel-to-steamefficiency. When the term “boiler efficiency” is used, it is important to know which typeof efficiency is being represented. Because thermal efficiency, which does not accountfor radiation and convection losses, is not an indication of the true boiler efficiency.Fuel-to-steam Efficiency, which does account for radiation and convection losses, is atrue indication of overall boiler efficiency. The term “boiler efficiency” should bedefined by the boiler manufacturer before it is used in any economic evaluation.Fuel to steam efficiencyFuel to steam efficiency is calculated using either of the two methods as prescribed bythe ASME (American Society for Mechanical Engineers) power test code, PTC 4.1. Thefirstmethod is input output method. The second method is heat loss method.Fuel-to-steam efficiencyis a measure of the overall efficiency of the boiler. It accountsfor the effectiveness of the heatexchanger as well as the radiation and convection losses.
It is an indication of the true boiler efficiency and should be the efficiency used ineconomic evaluations. As prescribed by the ASME Power Test Code, PTC 4.1, and thefuel-to team efficiency of a boiler can be determined by two methods; the Input-OutputMethod and the Heat Loss Method.
5. METHODS OF FINDING EFFICIENCY OF THE BOILER:Boiler efficiency determination:-There are two basic ways of determining the efficiency of a boiler: The Direct Method (Input-Output method); The Indirect Method;Both are recognized by the American Society of Mechanical Engineers (ASME) and aremathematically equivalent. They would give identical results if all the required heatbalance factors were considered and the corresponding boiler measurements could beperformed without error. Equivalent Evaporation:Equivalent evaporation may be defined as the evaporation which would be obtained ifthe feed water were supplied at 100o C and converted into dry saturated steam at 100oC(1.01325 bar pressure).Under actual working conditions of the boiler, supposema = actual weight of water evaporated in kg per kg of fuel,h0 = Enthalpy of 1 Kg of steam produced under actual working condition in kJ,h = Enthalpy of 1 kg of feed water entering the boiler in kJ,LS = Enthalpy of evaporation of 1 kg of steam at 100oC (2257 kJ), andme = equivalent evaporation in kg of water from and at 100oC per Kg of fuel burnt.BOILER EFFICENCYCALCULATION1) DIRECT METHOD:The energy gain of the working fluid
(water and steam) is compared withthe energy content of the boiler fuel.2) INDIRECT METHOD:The efficiency is the different betweenlosses and energy inputrequired to produce 1 kg of steam = (h0-h) kJ andHeat required producing ma kg of steam under actual working conditions= ma (h0-h) kJ.Equivalent evaporation in kg of water from and at 100oC per kg of fuel burnt,me = ma (h0-h) / Ls = ma (h0-h) / 2257For wet steam, me = ma (h0wet - h) / 2257 Factor of Equivalent Evaporation:Factor of Equivalent Evaporation is the ratio of heat absorbed by 1 kg of feed waterunder actual working conditions to that absorbed by 1 kg of feed water evaporated fromand at 100oC (i.e. standard conditions)".Factor of equivalent evaporation = (h0 – h) / Ls = (h0 – h) / 2257The mass of water evaporated is also expressed in terms of "Evaporation per hour persquare meter of heating surface of the boiler"Evaporation per m2 of heating surface= m kg per hour / Total area of heating surface in m2Where, m is the actual mass of water evaporated in kgThe Direct MethodThis was standard for a long time, but is little used now. According to this method theboiler efficiency is defined as, the ratio of the heat utilized by feed water in converting itto steam, to the heat released by complete combustion of the fuel used in the same time,i.e., output divided by the input to the boiler. The output or the heat transferred to feedwater is based on the mass of steam produced under the actual working conditions. Theinput to a boiler or heat released by complete combustion of fuel may be based on thehigher calorific value of the fuel.Boiler Efficiency = ma (h0-h) / C.V.Where, ma = actual evaporation in kg per kg of fuel burnt,h0 = Enthalpy of 1 kg of steam produced under actual working condition in kJ,h = Enthalpy of 1 kg of feed water entering the boiler in kJ and.C.V. = calorific value of fuel in kJ/kg
If a boiler is provided with an economizer and a super heater, then each of these elementsof a boiler will have its own efficiency. If the boiler, economizer & super heater areconsidered as a single unit, the efficiency in that case is known as the overall efficiencyof the boiler plant or efficiency of the combined boiler plant.Economizer efficiencyEconomizer is placed in between boiler and chimney to recover heat from the hot fluegases which are released in atmosphere through chimney.The efficiency of the economizer is the ratio of the heat gained by the feed water passingthrough the tubes of economizer and the heat given away by the hot flue gases passingover the tubes of the economizer.Economizer efficiency = ma (t2 - t1) / mf × Cp (tf1 - tf2)Where,ma = mass of steam produced per kg of fuel burntmf = mass of flue gases produced per kg of fuel burnt.Cp = specific heat of flue gasest1 = Feed water temperature entering economizert2 = Feed water temperature leaving economizertf1= Temperature of hot flue gases entering economizertf2 = Temperature of hot flue gases leaving economizer.Super heater efficiencySuper heater is normally placed directly after the furnace in the way of hot flue gases orin the furnace itself. The dry saturated steam is drawn from the boiler steam drum andpassed through the super heater coil where, at constant pressure, maximum heat isobserved by the steam & converted into superheated steam.The efficiency of super heater may be stated as the ratio of the heat gained by the drysaturated steam passing through super heater coils & heat given away by the hot gasespassing over the super heater coils.If super heater is placed in the furnace, in front of burners, radiation heat is alsoabsorbed.Super heater efficiency = ma [H + Cps (tsup - tsat)] / mf Cpf (tfi - tfo)Where,ma = weight of steam produced in kg per kg of fuel burntmf = weight of hot flue gases generated in kg per kg of fuel burnt,tsat = Temperature of steam entering the super heater,tsup = Temperature of steam leaving the super heater,
tfi = Temperature of hot gases entering the super heater.tfo = Temperature of hot gases leaving the super heater,Cpf = specific heat of hot gases at constant pressureCps = specific heat of steam at constant pressure.Advantages• Quick evaluation• Few parameters for computation• Few monitoring instruments• Easy to compare evaporation ratios with benchmark figuresDisadvantages• No explanation of low efficiency• Various losses not calculated The Indirect Losses MethodThe efficiency of a boiler equals 100% minus the losses. Thus, if the losses are knownthe efficiency can be derived easily. This method has several advantages, one of which isthat errors are not so significant: for example, if the losses total 10% then an error of1.0% will affect the result by only 0.1%.The losses method is now the usual one for boiler efficiency determination. In fact thereis no provision on many modern boilers for fitting coal weighing equipment, in whichcase the direct method cannot be used.Another point to bear in mind is that if a boiler is tested and found to have an efficiencyof, say 94%, it would be quite wrong to imagine that it is operated normally at thatefficiency. During testing, particular care is taken to keep the steam pressure,temperature and so on, as steady as possible and there is neither blow down nor sootblowing. Also the boiler is probable tested immediately after a soot blow. So there aremany factors common to normal operation that are absent when testing. Thus the testefficiency is probable the best that can be attained and for normal operation the valuewill be less. Factors Affecting EfficiencyThe following factors affect the efficiency of a given power plant.
Design choices. Designs for natural gas and coal-fired power plants represent atrade off between capital cost, efficiency, operational requirements, and availability. A steam turbine system that operates at a highertemperature and pressure can achieve a higherefficiency . Efficiency as a function of temperature and pressureThe higher temperatures and pressures,however, require more exotic materials ofconstruction for both the boiler and turbine, thus thecapital cost goes up. Thetechnology has been proven and demonstrated since the 1950s. Theproblemswere severe superheater material wastage, unacceptable creep, and thermalfatigue cracking experienced when metal temperatures exceededapproximately 1,025°F.1 Theissue was corrosion and strength at these extreme conditions. Heat integration represents another trade off. Rather than transferring cooling water to a processstream that needs to be cooled down and steam to another process stream that needs to be heatedup, the work can be partially accomplished by bringing the two streams into thermal contact viaa heat exchanger. There is a significant efficiency benefit, but process-process heat exchangers can causeoperational problems, especially during transient phases and in the event of fouling or fluidleakage across the exchanger. Thus heat integration represents a trade off between efficiency andavailability. Unit role, peaking, base loading, etc, affect design and operational practices of usingunits for a role other than which they were designed. Old base load design units are often usedfor cycling duty. The supercritical to ultra-supercritical units are not capable ofcycling without reducing longevity and ultimately the efficiency for which wasthe ultimate purpose of additional investment.Operational Practices. Efficiency can be improved by pressing over fire air to the minimum, fully utilizing heatintegration systems, staying after steam leaks and exchanger fouling, and a large number of otherpractices. Operating at full load capacity continuously will enhance efficiency. However thereality is that load is ever changing and the requirements of market based systems focus onreliability and leads to the inability to always run at full load.Fuel.Among coals the higher ranking coals enable higher efficiency because they contain less ash andless water. However additional coal production is largely focused on the Powder River Basinwhich is sub-bituminous.
Pollutant control. The level of pollutant emission control (including thermal) effects efficiency. NOx reductionunits and SOx scrubbers represent parasitic loads that decrease net generation and thus reduceefficiency. 6. IMPROVING ENERGY EFFICIENCY OF BOILER SYSTEMSWhen considering boiler energy savings, invariably the discussion involves the topic of boilerefficiency.The boiler suppliers and sales personnel will often cite various numbers, like the boiler has athermal efficiency of 85%, combustion efficiency of 87%, a boiler efficiency of 80%, and a fuel-to-steam efficiency of 83%. What does these mean?Typically, 1) Thermal efficiency reflects how well the boiler vessel transfers heat. The figure usually excludes radiation and convection losses. 2) Combustion efficiency typically indicates the ability of the burner to use fuel completely without generating carbon monoxide or leaving hydrocarbons unburned. 3) Boiler efficiency could mean almost anything. Any fuel-use figure must compare energy put into the boiler with energy coming out. 4) "Fuel to steam efficiency" is accepted as a true input/output value.
Each term represents something different and there is no way to tell, which boiler will use lessfuel in the same application! The trouble is that there are several norms to determine theefficiencies figures and it is practically very difficult to verify these without costly testprocedures. The easiest and most cost effective method is to review the basic boiler design dataand estimate the efficiency value on five broad elements.Boiler Stack Temperature: Boiler stack temperature is the temperature of the combustion gases leaving the boiler. This temperature represents the major portion of the energy not converted to usable output. The higher the temperature, the less energy transferred to output and the lower the boiler efficiency. When stack temperature is evaluated, it is important to determine if the value is proven. For example, if a boiler runs on natural gas with a stack temperature of 350°F, the maximum theoretical efficiency of the unit is 83.5%. For the boiler to operate at 84% efficiency, the stack temperature must be less than 350°F.Heat Content of Fuel: The efficiency calculation requires knowledge of the calorific value of the fuel (heat content), its carbon to hydrogen ratio, and whether the water produced is lost as steam or is condensed, and whether the latent heat (heat required to turn water into steam) is recovered. Disagreements exist on what is considered an "energy input". Unfortunately any fuel hastwo widely published energy contents. They are:• The Higher Heating Value (HHV), also called Gross Calorific Value (GCV)• The Lower Heating Value (LHV), also called the Net Calorific Value (NCV)The gross calorific value (GCV) is the higher figure and assumes that all heat available form thefuel is to be recovered, including latent heat. In most equipment, this is not so the case, and thecalculations of efficiency based on gross calorific value will give maximum obtainableefficiencies much lower than 100%, due to this irrecoverable loss.Both the gross calorific value and net calorific value are equally valid, but for comparisonpurposes, a particular convention should be used throughout.Fuel Specification:The fuel specified has a dramatic effect on efficiency. With gaseous fuels having higher the hydrogen content, the more water vapor is formed during combustion. The result is energy loss as the vapor absorbs energy in the boiler and lowers the efficiency of the equipment. The specification used to calculate efficiency must be based on the fuel to be used at the installation. As a rule, typical natural gas has a hydrogen/-carbon (H/C) ratio of 0.31. If an H/C ratio of 0.25 is used for calculating efficiency, the value increases from 82.5% to 83.8%.Excess Air Levels:Excess air is supplied to the boiler beyond what is required for complete combustion primarily to ensure complete combustion and to allow for normal variations in combustion. A certain amount of excess air is provided to the burner as a safety factor for sufficient combustion air.Ambient Air temperature and Relative Humidity:
Ambient conditions have a dramatic effect on boiler efficiency. Most efficiency calculations use an ambient temperature of 80°F and a relative humidity of 30%. Efficiency changes more than 0.5% for every 20°F change in ambient temperature. Changes in air humidity would have similar effects; the more the humidity, the lower will be the efficiency.Comparing these five factors along with the stated efficiency will make you understandefficiency values more thoroughly. An important thing to note is to make the comparisons onequal footings. COMBUSTION EFFICIENCYThe combustion efficiency test is your primary tool for monitoring boiler efficiency. A visual(opacity) technique to check change in flame shape, length, color, noise and smokecharacteristics is the first early indicators of potential combustion related problems. But inpractice, combustion efficiency is verifiable only with a flue gas analyzer. The stack temperatureand flue gas oxygen (or excess air) concentrations are primary indicators of combustionefficiency.The Logic of Combustion Efficiency TestsThe “combustion efficiency” test determines how completely the fuel is burned, and howeffectively the heat of the combustion products is transferred to the steam or water.Your boiler burns fuel efficiently if it satisfies these conditions: • It burns the fuel completely; • It uses as little excess air as possible to do it; • It extracts as much heat as possible from the combustion gases.The combustion efficiency test analyzes the flue gases to tell how well the boiler meets theseconditions. The test is essentially a test for excess air, combined with a flue gas temperaturemeasurement.Excess AirThe only purpose of bringing air into the boiler is to provide oxygen for combustion. Bringing intoo much air reduces efficiency because the excess air absorbs some of the heat of combustion,and because it reduces the temperature of the combustion gases, which reduces heat transfer. Thetemperature of the flue gas indicates how much energy is being thrown away to the atmosphere.There is theoretical or stoichiometric amount of air required for complete combustion of fuel. Inpractice, combustion conditions are never ideal, and additional or “excess” air must be suppliedto completely burn the fuel. When the air falls below the stoichiometric value, there is some fuelthat is not burned completely. This partially burned fuel creates smoke, leaves deposits onfiresides, and creates environmental problems. Unburned fuel may also represent a significantwaste of energy. The amount of waste depends on the energy content of the unburned fuel
Excess Air V/s Boiler EfficiencyThe table below relates the O2 levels to the excess air and combustion efficiency when seentogether with stack temperatures.On well designed natural gas-fired systems, an excess air level of 10% is attainable and for fueloil system 15% is a reasonable figure.An often stated rule of thumb is that 100% excess air reduces the boiler efficiency by 5% orboiler efficiency can be increased by 1% for each 15% reduction in excess air.Example: A boiler consumes 55 MMBtu per hour of natural gas while producing 5 lb/hr of 150psig steam. Stack gas measurements indicate an O2 level of 7% corresponding to an excess airlevel of 44.9% and with a flue gas less combustion air temperature of 400°F.
SolutionThe cost savings shall be provided by equation:Cost Savings = Fuel Consumption x (1 – Eff. Initial /Eff. Tune up) x steam costFrom the table, the initial boiler combustion efficiency is 78.2% and after tune-up the boilercombustion efficiency increases to 83.1%. Therefore:Cost Savings = 55 x (1 – 78.2/83.1) x 5 = $ 16.2 per hourOr the cost savings will be $129,600 per annum for 8,000 hours of operation per year.Optimum Excess Air Fuel Type Minimum + Excess = Total O2 recommended Natural Gas 0.5 – 3.0% 0.5 – 2.0% 1.0 – 5.0% Fuel Oils 2.0 – 4.0 % 0.5 – 2.0% 2.5 – 6.0% Pulverized Coal 3.0 – 6.0 % 0.5 – 2.0% 3.5 – 8.0% Coal Stoker 4.0 – 8.0% 0.5 – 2.0% 4.5 – 10.0%• If two boilers are stated as operating at the same stack temperature and one has less heatingsurface, stack temperature on the boiler with less heating surface should be challenged.• If two boilers are stated as operating at 15% excess air and one has a very complex burnerlinkage design or does not include a high-quality air damper arrangement, it is questionable thatit will operate at the stated excess air level.• If two boilers of similar length and width are compared and one has more flue gas passes(number of times the flue gas travels through the boiler heat exchanger), the boiler with thegreater number of passes should have a lower stack temperature. Combustion Efficiency Indicators 1) As a rule, the most efficient and cost-effective use of fuel takes place when the CO2 concentration in the exhaust is maximized. Theoretically, this occurs when there is just enough O2 in the supply air to react with all the carbon in the fuel. 2) The absence of any O2 in the flue gas directly indicates deficient combustion air while presence indicates excess air. Ideally, the O2 levels shall be maintained close to 2% to 4% (gas & oil). 3) Carbon monoxide (CO) is a sensitive indicator of incomplete combustion; its levels should range from zero to 400 parts per million (ppm) by volume. The presence of a large amount of CO in flue gas is a certain indicator of deficient air.
Combustion Gas Concentrations at Percent of the Theoretical Combustion AirProceeding from left to right, the curves highlight 4 things: 1) When too little air is supplied to the burner, there is not enough oxygen to completely form CO2. It suggests incomplete combustion and is characterized by large amount of carbon monoxide (CO) in the stack. 2) As the air level is increased and approaches 100% of the theoretical air, the concentration of CO molecules decreases rapidly and CO2 reaches a maximum value. This suggests almost complete combustion. 3) Withl more combustion air, excess air begins to dilute the exhaust gases, causing the CO 2 concentration to drop and increase the concentration of O2. The CO level is practically negligible. A 10 to 15% excess air is desired for safe and reliable operation. 4) The knee of the curve (zero CO), corresponds to the point of maximum furnace efficiency. Carbon monoxide in the flue gas (measured in ppm of CO), stays at a fairlylow level at high excess air, but rises sharply as excess air is reduced below the optimum level.
Flue gas Analysis - What to measure, O2 or CO2?Flue gases contain a composition of oxygen, carbon dioxide, carbon monoxide and sulfurdioxide. All of these gases are easily detectable with modern instrumentation. Oxygenmonitoring is the most popular measure as it has a single value relationship with excess air.The oxygen test is more accurate than the carbon dioxide test. The reason is that the relativechange in oxygen is much greater than the relative change in carbon dioxide for a given changein excess air. For example, with No. 2 oil, an increase in excess air from 2% to 10% causesoxygen in the flue gas to increase by a factor of five, a change that you can measure easily. Onthe other hand, the same increase in excess air causes carbon dioxide to drop by only 10%, adifference that is more difficult to measure accurately.Another advantage of the oxygen test is that the results are much less sensitive to variations inthe chemical composition of the fuel. The amount of carbon dioxide in the flue gas depends onthe amount of carbon in the fuel, and the amount of excess air is calculated from this carbondioxide value. There are large differences in the chemical composition of some fuels, such asindustrial by-product gases. All liquid and gas fuels have some variation.In contrast, the oxygen test provides a direct indication of excess air. Variations in carboncontent do not affect the results of the oxygen test at all, and variations in the total energycontent of the fuel affect the oxygen content much less than they affect the carbon dioxidecontent.Unlike the carbon dioxide test, the oxygen test works only in the region of excess air. There is nooxygen to measure when there is no excess air. This is not a problem in normal testing, becauseyou should always operate boilers with a small amount of excess air.Additional Tests for Incomplete CombustionTo fine-tune the excess air, you may need an additional test that detects small amounts ofincompletely burned combustion products. Two common tests for this purpose are smoke densityand carbon monoxide in the flue gas.Carbon Monoxide TestThe carbon monoxide content of flue gas is a good indicator of incomplete combustion with alltypes of fuels, as long as they contain carbon. Carbon monoxide in the flue is minimal withordinary amounts of excess air, but it rises abruptly as soon as fuel combustion starts to beincomplete. This makes it an excellent indicator when making your final adjustments of the air-fuel ratio.An excessive level of carbon monoxide that occurs in the normal region of the air-fuel ratioindicates trouble within the boiler. Carbon monoxide rises excessively if any defect in the boilercauses incomplete combustion, even with excess air. This makes carbon monoxide testing anexcellent tool for discovering combustion problems, especially if it is used in combination with
oxygen testing. For example, the carbon monoxide test might reveal a fouled burner. It mightalso point toward a more subtle problem, such as a poor match of the burner assembly to thefirebox, causing a portion of the flame to strike a surrounding surface. (Cooling the flameinterrupts the combustion process, leaving carbon monoxide and other intermediate products ofcombustion in the flue gases.)Carbon monoxide also forms if there is a great excess of air. This is not a matter of practicalsignificance. Once you set the air-fuel ratio properly, the carbon monoxide content falls into theproper range if there are no other problems. Approach to Optimum Combustion ControlUsually the cause of excessive or deficient combustion is: 1) The Draft 2) Proper Air-Fuel MixDraft ControlThe major cause of boiler losses, both avoidable and unavoidable, is the boiler draft. Poor draftconditions alters the flame pattern thus inhibiting the fuel from burning properly and changingthe air-fuel ratio. • Insufficient draft prevents adequate air supply for the combustion process and results in smoky, incomplete combustion. • Excessive draft allows increased volume of air into the boiler furnace. The larger amount of flue gas moves quickly through the boiler, allowing less time for heat transfer to the waterside. The result is that the exit temperature rises, and this along with larger volume of flue gas leaving the stack, contributes to the maximum heat loss.If the boiler does not have a forced draft system, excess combustion air cannot be easily orproperly controlled. Strong consideration should be given to installing a forced draft systemunder this situation. Even with a forced draft system, it still may not be feasible to closelyregulate the amount of excess air because of burners that require proper air-fuel mix.If you are unable to maintain the CO2 levels > 12%, it indicates a worn out burner or problemwith the furnace draft. In these situations, the manufacturer‟s representative should be consultedto discuss upgrading the controls and equipment.Air-Fuel RatioThe efficiency of the boiler depends on the ability of the burner to provide the proper air to fuelmixture throughout the firing rate, day in and day out.The density of air and gaseous fuels changes with temperature and pressure, a fact that must betaken into account in controlling the air-to-fuel ratio. For example, if pressure is fixed, the mass
of air flowing in a duct will decrease when the temperature increases. The controls shouldtherefore compensate for seasonal temperature variations and, optimally, for day and nightEffects of Air Temperature on Excess Air LevelUsually the cause of improper Air-Fuel ratio is due to inadequate tolerance of the burnercontrols, a faulty burner or improper fuel delivery other than draft conditions. Often, the burnercannot provide repeatable air control and sometimes because of controller inconsistency itself,the burners are permanently set up at high excess air levels. The fact is you pay substantialdollars every time you fire the unit.If you are unable to maintain the CO levels < 400 ppm, it indicates the poor mixing of fuel andair at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization ofburner nozzle and deterioration of diffusers or spinner plates.Excess Air Control - Control & AutomationExcess air control (also referred to as O2 control) is important for optimum combustion and canbe achieved by means of adjusting burner airflow to match fuel flow.Various types of air-fuel combustion controls are utilized for this purpose. A brief description isas follows in order of sophistication and costs:On-off and high-low controls: The use of on-off and high-low controls is limited to processes that can tolerate cycles of temperature and pressure, such as heating applications.Position Proportional Control: This type of control also known as mechanical jackshaft control is the simplest type of modulating burner control used in small boilers with a fairly steady load. In these controls same firing rate signal is presented to both the fuel and air control elements and the „Fuel/Air‟ ratio is controlled by fixed positioners mounted to the positioning motor, typically a cam device. The play in the jackshaft and linkages needs settings with higher than- necessary excess air to ensure safe operation under all conditions. The range of oxygen control (oxygen trim) is limited. The control response must be very slow to ensure that the burner reaches a steady state before the oxygen trim acts.Parallel controls: These controls are usually applied to medium-sized boilers equipped with pneumatic controls. Separate drives in parallel controls adjust fuel flow and airflow, taking their signal from a master controller. Their performance and operational safety can be improved by adding alarms that indicate if an actuator has slipped or calibration has been lost. Also, an additional controller can be added to provide oxygen trim. Parallel controls have similar disadvantages to mechanical jackshaft controls.
Cross-limiting control: These controls are usually applied to larger boilers firing typically above 13,000 lbs/hr steaming capacity and having wide variations in load demands. This design can provide very close control of the air/fuel ratio throughout the burner‟s operating range without creating fuel-rich or air-rich mixtures, normally experienced in position-proportional systems. This control measures the flow of air and fuel and adjusts airflow to maintain the optimum value determined during calibration tests. Fuel rich conditions are avoided by a cross-limiting strategy, which uses high and low signal selectors to achieve a lead/lag effect with the airside. This lead/lag effect forces the fuel to lead the air as demand drops, thus creating a lean transition flame on loss of demand, and fuel to lag air on an increase in demand, which again creates a lean transition flame on increased demand. Operations are safer when airflow cannot drop below the minimum needed for the existing fuel. The cross-limiting when applied along with parallel control function, trims the fuel/air ratio to the best combustion ratio. This configuration allows a significantly greater number of combustion points on the combustion curve to control the fuel/air ratio. Oxygen Trim SystemsEvery 1% decrease in excess O2 from the stack, results in as much as ½ % increase in thermalefficiency.Automation plays vital role in controlling excess air and also benefits in process consistency,flexibility to load demands, ability to monitor, trend and bill the utilities in the process.When fuel composition is highly variable (such as refinery gas, hog fuel, or multi-fuel boilers),or where steam flows are highly variable, an on-line oxygen analyzer should be considered. Theoxygen “trim” system provides feedback to the burner controls to automatically minimize excesscombustion air and optimize the air-to-fuel ratio. It increases energy efficiency by one to twopercent. For very large boilers, efficiency gains of even 0.1 percent can result in significantannual savings.The use of O2 trim, only trims the amount of excess air above that required for completecombustion for a specific furnace design while not creating a fuel-rich furnace/stackenvironment. The burner design, fuel selection and load swing are all critical factors affecting thedecision to O2 trim in any given boiler.Unfortunately, high cost of purchasing and installing an oxygen analyzer discourage its use tosmall or medium boilers. Typically, its use is advantageous in large boilers that use between$100,000 and $1 million worth of fuel annually. But from the point of view of limiting
environment emissions and also to satisfy the authority having jurisdiction, it may be appropriateto install oxygen trim for smaller boilers even though the paybacks are little longer.Efficiency considerations with Fuel Oil and Natural Gas 1) Fuel oil Pressure and temperature directly affect the ability of oil to properly atomize and burn completely and efficiently. Changes promote flame failure, fuel-rich combustion, sooting, oil buildup in the furnace, and visible stack emissions. Causes include a dirty strainer, worn pump, faulty relief valve, or movement in linkage or pressure-regulating valve set point. Oil temperature changes typically are caused by a dirty heat exchanger or a misadjusted or defective temperature control. When oil is burned, an atomizing medium, either air or steam, is needed for proper, efficient combustion. Changes in atomizing media pressure cause sooting, oil buildup in the furnace, or flame failure. Changes result from a regulator or air compressor problem or a dirty oil nozzle. 2) Gas pressure is critical to proper burner operation and efficient combustion. Irregular pressure leads to flame failure or high amounts of carbon monoxide. It may even cause over or under firing, affecting the boilers ability to carry the load. Gas pressure should be constant at steady loads, and should not oscillate during firing rate changes. Usually, pressure varies between low and high fire. Therefore, readings should be compared to those taken at equivalent firing rates to determine if adjustments are needed or a problem exists. Gas pressure irregularities are typically caused by fluctuations in supply pressure to the boiler regulator or a dirty or defective boiler gas pressure regulator. It is important to provide automatic burner controls for safe and efficient operation. Improperly set operating controls cause the burner to operate erratically and stress the pressure vessel. Negative Effects of Improper CombustionThe negative effects of combustion on the environment – particularly greenhouse gas (GHG)emissions; global warming and acid rain are one of the greatest challenges facing the worldtoday. Unburned hydrocarbons, carbon monoxide, carbon dioxide, sulfur oxides & nitrogenoxides are all products of combustion that provide the greatest threat.Carbon monoxide:Carbon monoxide is a highly toxic gas associated with incomplete combustion.The CO level in the flue gas depends solely on combustion efficiency and not on the fuel, theburners or the design of the boiler. Inaccuracies on measurements due to stratification mightoccur with sample type sensors but essentially flue gas CO concentration is unaffected by airinfiltration, and thus gives a more certain indication of combustion.Carbon dioxide:
The CO2 content in flue gas reaches to a maximum, approximately at the ideal air/fuel ratio, andfalls off both with increasing and with decreasing excess air. Therefore, applying energyefficiency measures that reduce fuel consumption is crucial to reducing CO2 emissions.Nitrous & Sulfurous Oxides:SO2 and NOx emissions are primarily due to sulfur content of the fuel and combustion reactionsof N2 at high temperatures.Emissions of SO2 and NOx contribute to acid rain and condensation of these products inside thestack may lead to corrosion of chimney.SO2 emissions can be controlled by limiting the allowable sulfur content of the fuel and NO xemissions can be reduced by manipulating the combustion process.Managing combustion processes better and improving the efficiency of energy use & generationare two of the key strategies for reducing atmospheric emissions. Keeping boiler clean from sootUnder conditions of incomplete combustion, unburnt carbon particles get deposited in the formof soot on the inside of fire tubes.Except for natural gas, practically every fuel leaves a certain amount of deposit on the fireside ofthe tubes. This is called fouling, and it greatly reduces heat transfer efficiency of a boiler.Tests show that a soot layer just 0.8 mm (0.03 in) thick reduces heat transfer by 9.5 percent and a4.5 mm (0.18 in.) layer by 69 percent. As the layer of soot builds up, the stack temperature risesby about 100°F for 1mm thick soot coating. For every 40°F rise in stack temperature, boilerefficiency is reduced by 1%. That‟s a pretty good argument for regular tube cleaning.In the high temperature zones of a boiler system such as superheater, corrosion spots may occurdue to the melting of some of the components of the deposits having a low melting point. Also inthe heat recovery system like an economizer or preheater, corrosion due to sufhur trioxide mayshow up. Periodic off-line cleaning of radiant furnace surfaces, boiler tube banks, economizersand air heaters may be necessary to remove these stubborn deposits.Large boilers and those burning fuels with a high fouling tendency have strategically located sootblowers as in integral part of the boiler. Soot blowers are machines that mechanically drivebushes or scrapers through the tubes and clean the surfaces while the boiler is operating. Thesemachines, in turn, connect to powerful vacuums that draw the loosened soot from the tubes,simultaneously, leaving the tubes, boiler room and operator completely clean.Small boilers, including natural gas-fired boilers should be opened regularly for checking thedeposition. The cleaning can be handled using portable powerful air motors, which drive flexibleshafts fitted with a wide variety of cleaning tools.
Energy Loss due to Improper De-aeration of Boiler FeedwaterSince makeup water contains considerable amounts of dissolved oxygen, corrosion becomes acritical reliability concern because high heat intensity at the boiler tubes accelerates the oxidationprocess. Therefore, feedwater to the boiler must be made oxygen free.Also steam with as little as 1% by volume of air in it, can reduce the efficiency of heat transferby up to 50%. Therefore, attention to the de-aeration process as well as to the proper functioningof air vents is of significant importance.Deaerator is most commonly used equipment to get rid of dissolved oxygen. Very briefly, thedeaeration process uses live steam to bring the feedwater up to approximately 105°C andmechanical agitation to drive off the oxygen from the water. The liberated dissolved oxygenmust be continuously removed from the deaerator, and hence, a small amount of purge steamfrom the deaerator is an accepted industrial norm.The size of this required purge depends on factors like design capacity, efficiency and oxygenloading on the deaerator unit. Typically, the vent rate is around 0.5 to 1% for smaller, moreefficient units and having lower make-up water. High make-up water requires vent rate of over1%.Example: A boiler with 100,000 lb/hr capacity vent out 1,000 lb/hr of steam. That amounts to 8million pounds of steam per year costing $64,000.00 at $8.00 per thousand pounds. Additionalventing over and above this 1% can quickly add up to hundreds of thousands of dollars a year.Dearators must be fitted with auto-controls and safety devices to limit the purge requirement tothe required levels. Note that the higher the makeup water, the higher is the dissolved oxygenloading. All efforts to maximize condensate recovery are therefore very important.In order to minimize oxygen pitting, a volatile oxygen scavenger such as diethylhydroxyamine(DEHA) could be utilized. DEHA provides better results, as it scavenges oxygen and passivates
7. BLOWDOWN WATERWhen water is converted to steam, the dissolved solids do not travel with the steam, but are leftbehind in the boiler water. Fresh makeup water enters the boiler to replace the amount lostthrough steam evaporation. When this new water is converted to steam, more solids are leftbehind. As steam is continually produced, evaporated, and replaced with new water, the amountof solids in the boiler continues to increase indefinitely until the water is unable to dissolve itsown impurities or hold them in solution. These will inevitably collect in the bottom of the boilerin the form of sludge, and are removed by a process known as bottom blowdown.Cycles of concentration is an indicator of the amount of solids buildup in the water.For every pound of steam generated, a pound of water must be replaced. The amount of solids inthe water will have doubled when the amount of new water that has entered the boiler is equal tothe amount of water that was used to originally fill the boiler. When the amount of solids hasdoubled, there are 2 cycles of concentration in the water. When the amount of solids has tripled,there are 3 cycles of concentration. Effects of Insufficient or Excessive BlowdownInsufficient blowdown may lead to carryover of boiler water into the steam, or the formation ofdeposits. Excessive blowdown will waste energy, water, and chemicals. The optimum blowdownrate is determined by various factors including the boiler type, operating pressure, watertreatment, and quality of makeup water. Blowdown rates typically range from 4% to 8% ofboiler feedwater flow rate, but can be as high as 10% when makeup water has high solidscontent.
For example, consider a 50,000 lb/hr boiler operating @ 125 psig has a blowdown heat contentof 330 Btu/lb. If the continuous blowdown system is set at 5% of the maximum boiler rating,then the blowdown flow would be about 2,500 lb/hr containing 825,000 Btu.At 80 percent boiler efficiency, this heat requires about 1,050 cu- ft / hr of natural gas, worthabout $42,000 per year based on 8,000 hrs of operation per year at $5 per 1,000 cu-ft.Blowdown CalculationsThe quantity of blowdown required to control boiler water solids concentration is calculated byusing the following formula:If maximum permissible limit of TDS as in a package boiler is 3,000 ppm, percentage make upwater is 10% and TDS in feed water is 300 ppm, then the percentage blow down is given as:If boiler evaporation rate is 10,000 lb/hr, then the required blowdown rate is Chloride TestChloride is chosen as the indicator for cycles of concentration because: 1) It is always present in the makeup water 2) It does not change character when heated 3) It do not react with the chemicals in the water treatment, and 4) It does not leave the water in the boiler when steam is producedIf the Chloride in the water doubles, all the solids would have doubled.Example:If the makeup chlorides are 20 ppm and the boiler water chlorides are 100 ppm, the boiler is at 5cycles of concentration. If makeup chlorides are at 30 ppm and the boiler water is at 120 ppm,the boiler is at 4 cycles of concentration.
The Chloride Test is run on a sample of the raw water and on a sample of the water from theboiler sight glass. When the Chloride reading of the boiler water is 6 times the Chloride readingof the raw water, there are 6 cycles of concentration.Specific Conductance TestThe second test used for regulating blowdown is specific conductance. A conductivity meter isused to measure the conductivity of the "make up" water as compared to the conductivity of theboiler water. The ratio of the two figures is the "cycles of concentration".Example: If the makeup water conductivity is 300 umhos and boiler water conductivity is 2100umhos, 2100 ÷ 300 equals 7 cycles of concentration.Important: In general, the boiler should never be operated over 10 Cycles of Concentration Methods for controlling blowdown Blowdown systems could be either manually or automatically controlled. 1) Manual control: The amount of blowdown is determined by performing tests to determine the amount of dissolved solids in the boiler water. The operator must be thoroughly instructed in the correct blowdown procedure. Mud or bottom blowdown is usually a manual procedure performed for a few seconds on intervals of several hours. It is designed to remove suspended solids that settle out of the boiler water and form a heavy sludge. 2) Automatic blowdown: The automatic controllers sense the boiler TDS in terms of electrical conductivity and automatically open or close the surface blowdown lines to control exactly the right minimum level. The operator must check that the controls are set for required blowdown and that they function properly. Automatic controls can have a significant impact on efficiency, especially if steam loads vary widely. Surface or skimming blowdown is designed to remove the dissolved solids that concentrate near the liquid surface. Surface blowdown is often a continuous process.Uncontrolled or continuous blowdown is wasteful. Automatic blowdown controls can sense andrespond to boiler water conductivity much more effectively.Energy Savings due to Reduction in BlowdownAssuming the feedwater consists of 60% returned condensate and 40% makeup water; theanalyzed sample tests alkalinity (as CaCO3) of 70 ppm and the maximum allowed is 700 ppm.Therefore the concentration limit is 10.If additional recovery results in a 67% condensate, feedwater quality is improved and a lowerblowdown rate results. The total alkalinity (as CaCO3) is reduced to 70 to 58, allowing the
concentration to increase from 10 to 12. Correspondingly the blowdown rate is proportionatelyreduced by 1.7% from 10 to 8.3 percent.Actual blowdown and feedwater requirements for steam production of 100,000 lb/day arecalculated by using several formulas:F = E / (1- B)Consequently, returning 7% more condensate of the boiler realizes a fuel savings of $21,504 perannum assuming 350 days operation.Blowdown Heat RecoveryAlthough reducing blowdown results in substantial fuel savings, this function cannot beeliminated entirely. A boiler operating on high quality feedwater needs very little blowdown,while equipment using feedwater containing solids, alkalinity or silica requires a much higherrate, may be even continuous discharge.Flash Steam RecoveryFlash steam heat recovery is a method for recovering at least 85% of the blowdown heatingvalue.About half of the heat contained in the blowdown water is recovered in the form of flash steamby discharging the flow to a flash tank, usually operated at 5 psig. A portion of the blowdownflashes to steam at the lower pressure and is available for use in the deaerator or for other lowpressure demands.Flash steam recovery is calculated using the formula:A = (H – W) / LWhere: • A = Flash steam % • H = Boiler blowdown water heat content, Btu/lb • W = Water heat/content at flash pressure, Btu/lb • L = Steam latent heat content at flash pressure, Btu/lbAssuming, a flash tank is added to a boiler operating at 235 psig and generating 1,000,000 lb/dayof steam, the blowdown rate is 5%, or 52,632 lb/dayA = (376 – 196) / 960A = 0.1875 or 18.75%Daily heat recovery is calculated by applying the formulaG=AxJxK
Where: • A = Flash steam, % • G = Daily heat recovery, Btu • J = Blowdown, lb/day• K = (L+W), which is heat content of saturated vapor at flash pressure, Btu/lbUsing the numbersG = 0.1875 x 52,632 x 1156= 11,407,986 Btu/dayBlowdown heat recovery Heat exchangers can reclaim the sensible heat from the blowdown that goes into sewerage forheating boiler makeup water and the like. In most cases, the heat exchanger is designed to reduce the temperature of the blowdown waterto within 20 °F of the temperature of the makeup water.Additional heat recovered is calculated from the following formula:M = J x (1- A) x (W – P)Where:M = Additional daily heat recovery, BtuP = Water heat content at exchanger outlet, Btu/lbM = 52,356 x (1- 0.1875) x (196-48)M = 6,296.531 Btu/dayTotal heat recovery from the flash steam and the heat exchanger is 17,704,517 Btu/day;Total heating value in the blowdown is 52,632 x 376 Btu/lb or 19,789,632 Btu/day. The twomethods captured 89% of the blowdown water energy. Optimum Pipe SizingSteam piping transports steam from the boiler to the end-use services whereas condensate returnpiping transports condensate back to the boiler. Important characteristics of well-designed steam& condensate system piping are these that are adequately sized, configured, insulated andsupported.
The steam flow through the pipe in terms of pressure and volume required is dictated by theprocess needs. Proper sizing of steam pipelines help in minimizing pressure drop. There arebroad limits on the velocities of steam in pipes imposed by considerations of related erosion ratesetc. On the basis of practical experience, acceptable velocities limits are: • Superheated 50-70 m/sec • Saturated 30-40 m/sec • Wet or Exhaust 20-30 m/secVelocities exceeding these are likely to generate noise and erosion, specifically if there is wetsteam. For shorter branch connections, it is advisable not to exceed 15 m/s. The startingconditions at the beginning of the steam main are usually provided by the boiler specifications.There are fraction allowances in a pipe, the friction factor „F‟ depending on the Reynolds numberand the relative roughness of the pipes internal surface, defined as the ratio of a mean roughnessheight „k‟ to the pipe diameter. For commercial, non-corrosive steel tubes commonly used insteam and water service, k may be taken to be 0.05 mm. As the network in general will includetees, bends, valves etc, these will also contribute to overall friction.Standard data tables are available that help in making the final selection. The equations, onwhich these data is based, make use of the following empirical relation:The following simple rules may serve as guidelines:a) Ensure that the distributing pipework is of the right size. Oversized pipes increase capital,maintenance and insulation costs, and generate higher surface heat losses. Undersized pipesrequire higher pressure and extra pumping energy and have higher rates of leakage.b) Redundant, obsolete pipework wastes energy as it is kept at the same temperature as the restof the system; the heat loss per length of pipe remains the same. The heat losses from extrapiping add to the space heat load of the facility and thus to the unnecessary ventilation and air-conditioning needs. Moreover, redundant pipework receives scant maintenance and attention,incurring further losses. c) In a neglected steam distribution system, leaks are common in the piping, valves,process equipment, steam traps, flanges, or other connections. Fixing steam leaks is a simple andlow cost opportunity to save energy and money.d) Install meters and keep track of where the steam is going. The facility-wide and individualprocess-unit steam balances will help in accessing losses in a better way.e) Important configuration issues are flexibility and drainage. With respect to flexibility, pipingespecially at equipment connections, needs to accommodate thermal reactions during systemstartups and shutdowns. With respect to drainage, the piping should be equipped with a sufficientnumber of appropriately sized drip legs for effective condensate drainage.f) All pipes should have fall in the direction of the steam flow typically not less than 125 mm forevery 30 meter length. The piping should be pitched properly to promote the drainage ofcondensate to these drip lines. Typically these drainage points experience two very differentoperating conditions: normal operation and startup. Both load conditions should be considered inthe initial design.
g) Drain points should be provided at intervals of 30 to 45 meters along the main. Drain pointsshould also be provided at low points in the mains and where the steam main rises. Ideallocations are the bottom of expansion joints and before reduction and stop valves.h) Drain points in the main lines should be through an equal tee connection only. It is preferableto choose open bucket or TD traps on the account of their resilience.i) The branch lines from the mains should always be connected at the top. Otherwise, the branchline itself will act as a drain for the condensate.j) Expansion loops are required to accommodate the expansion of steam lines while starting fromcold.k) To ensure dry steam in the process equipment and in branch lines, steam separators can beinstalled as required.
Proper Insulation Of Steam PipeImportant insulation properties include thermal conductivity, strength, abrasion resistance,workability, and resistance to water absorption.Thermal conductivity is the measure of heat transfer per unit thickness. Thermal conductivity ofinsulation varies with temperature; consequently, it is important to know the right temperaturerange when selecting insulation. In general, the lower the thermal conductivity, the higher willthe resistance to heat transfer be.Some common insulating materials used in steam piping include calcium silicate, mineral fiber,fiberglass, perlite, and cellular glass. The American Society for Testing and Materials (ASTM)provides standards for the required properties of these and other insulation materials.Insulation blankets (fiberglass and fabric) are commonly used on steam distribution components(valves, expansion joints, flanges etc.) to enable easy removal and replacement for maintenancetasks.The following simple rules may serve as guidelines on insulation: a) The smaller the pipe diameter, the thinner the insulation. b) Good quality insulation with low thermal conductivity is far better than a poor quality material. c) The higher is the temperature of the surface to be insulated; the better is the return on investment. d) It is the initial 1 ½” thickness of insulation which is critical to heat loss. It is more important that all steam pipework be insulated to some degree, rather than having some pipework well insulated while other sections are left bare. Therefore it is always advantageous to cover up all fittings, valves, supports and flanges. e) Running pipes in groups greatly reduce heat losses. All future installations should incorporate this principle. f) Drafts and air movements greatly increase heat losses especially when pipe are not well insulated. Steam Use in Heating The primary objective of the effective steam utilization is to maximize the transfer of heatof the steam to the end use equipment. The following need to be noted:Providing dry steam for process: The best steam for industrial process heating is dry saturated steam; neither wet nor superheated. If steam is wet, the trapped moisture particles reduce the total heat in the steam (since they carry no latent heat), and increase the resistant film of water on the heat transfer
surfaces, thereby slowing down the rate of heat transfer. Superheated steam is not so practical because it gives up its heat slower than the condensation heat transfer of saturated steam. Boiler without a super-heater cannot deliver perfectly dry saturated steam. At best, it can deliver only 95% dry steam. The dryness fraction of steam depends on various factors, such as level of water in the boiler drum, the effect of peak loads, the surging within the boiler, the pressure on the water surface in the boiler and the solids content in the boiler water. Any one of these factors can cause droplets of water to be a part of the steam. A steam separator may be installed on the stem main as well as on the branch lines to reduce the wetness in steam and improve the quality of steam going to the user units.Using Steam at Lowest Pressures: Reducing the boiler‟s steam operating pressure to the minimum needed by the end user, or reducing the temperature of the fluid (not overheating the fluid), can dramatically affect the energy savings. These savings come from burning less fuel in the boiler or heater and lowering the amount of heat lost in the piping system. To change the system‟s operating pressure or fluid temperature, verify that the boiler and end devices can run at the lower pressure (temperature). The potential environmental and dollar savings are worth investigating. Key end use equipment includes, heat exchangers, unit heaters, vessels, tanks and other process-specific steam use equipment. In one of the liquor factory, the tanks were found to be operating at a temperature of 180°F when it was known that a temperature of 150°F was adequate for the particular process. The unnecessary overheating was causing a wasteful use of about 13,700 gallons of fuel oil a year. A simple temperature control device with temperature sensor and „On-Off‟ control valve on the steam can prevent this energy loss. Caution: The energy manager should consider pressure reduction carefully before implementing it. Adverse effects, such as an increase in water carryover from the boiler owing to pressure reduction, may negate any potential saving. Pressure should be reduced in stages and no more than a 20 percent reduction should be considered.Heating by Direct Injection In plants where water or process liquor is heated by direct steam injection, one can see the liquid in the tank boiling away, thereby creating clouds of vapor. This is waste of steam; besides it creates unpleasant working conditions. Ideally, the injected steam should be condensed completely as the bubbles rise through the liquid. This is possible only if the inlet pressure is kept low around 7 psig and certainly not over 14 psig. Recommended arrangement includes a sparge pipe with large number of small diameter holes (2 to 5 mm) facing downwards should be placed in the tank.Proper Air Venting A 0.25 mm thick air film offers the same resistance to heat transfer as a 330 mm thick copper wall. Air in a steam system will also affect the system temperature. The presence of
air inside the process equipment will reduce the partial pressure of steam in the steam-airmixture, thus dropping the overall temperature of the steam-air mixture, which is the heatingmedia. It is however, impossible to avoid the entry of air into a steam system that is workingintermittently. If the steam condenses during the shut downs, air tends to be sucked in due tothe partial vacuum created. Air is also pushed into the process equipment from the steammains at the time of start up. The situation can be improved by installing properly sized airvents at appropriate positions in the pipelines, and equipment at the highest points.Automatic air vents for steam systems (which operate on the same principle as thermostaticsteam traps) should be fitted above the condensate level so that only air or steam-air mixturescan reach them.
8. Boiler TechnologiesBoiler technology the world over has evolved vastly over the years. From the conventionalpulverized coal boilers to fluidised bed combustion technology and multi-fuel firing boilers, theindustry has indeed come a long way.This write-up describes the available and emerging technology options, their benefits andlimitations. CURRENT TECHNOLOGIESPulverised fuel boiler is the most commonly used method in thermal power plants, and is basedon many decades of experience. Units operate at close to atmospheric pressure, simplifying thepassage of materials through the plant.Most coal-fired power station boilers use pulverised coal, and many of the larger industrialwatertube boilers also use this fuel. This technology is well developed, and there are thousandsof units around the world, accounting for well over 90 per cent of coal-fired capacity.The coal is ground (pulverized) to a fine powder so that less than 2 per cent is +300 micro metre(μm) and 70-75 per cent is below 75 microns, for bituminous coal. The pulverized coal is blownwith part of the combustion air into the boiler plant through a series of burner nozzles. Secondaryand tertiary air may also be added. Combustion takes place at temperatures from 1,300 to 1,700o C, depending largely on coal grade. Particle residence time in the boiler is typically two to fiveseconds, and the particles must be small enough for complete combustion to have taken placeduring this time.This system has many advantages such as the ability to fire varying qualities of coal, quickresponses to changes in load, use of high preheat air temperatures, etc. Pulverised coal boilershave been built to match steam turbines, which have outputs of between 50 and 1,300 Mwe. Inorder to take advantage of the economies of scale, most new units are rated at over 300 Mwe, butthere are relatively few really large ones with outputs from a single boiler-turbine combination of
over 700 Mwe. This is because of the substantial effects such units have on the distributionsystem if they should “trip out” for any reason, or be unexpectedly shut down.
Fluidised bed combustionFluidized bed combustion has emerged as a viable alternative and has significant advantagesover the conventional firing system and offers multiple benefits. Some of the benefits arecompact boiler design, fuel flexibility, higher combustion efficiency and reduced emission ofnoxious pollutants such as SOx and NOx. The fuels burnt in these boilers include coal, washeryrejects, rice husk, bagasse and other agricultural waste. Fluidised bed boilers have a widecapacity range – from 0.5 T per hour to over 100 T per hour.There are three basic types of fluidized be combustion boilers: • Atmospheric classic fluidized bed combustion system (AFBC). • Atmospheric circulating (fast) fluidized bed combustion system (CFBC) • Pressurised fluidized bed combustion system (PFBC).AFBC/ Bubbling bedIn AFBC, coal is crushed to a size of 1-10 mm depending on the rank of coal, and type of fuelfed into the combustion chamber. The atmospheric air, which acts as both the fluidisation air andcombustion air, is delivered at a pressure and flows through the bed after being preheated by theexhaust flue gases. The velocity of fluidizing air is in the range of 1.2 to 3.7 m per second. Therate at which air is blown through the bed determines the amount of fuel that can be reacted. Almost all AFBC/ bubbling bed boilers use in-bed evaporator tubes in the bed of limestone,sand and fuel for extracting the heat from the bed to maintain the bed temperature. The bed depthis usually 0.9 m to 1.5 m and the pressure drop averages about 1 inch of water per inch of beddepth. Very little material leaves the bubbling bed-only about 2 to 4 kg of solids are recycled perkg of fuel burnt.The combustion gases pass over the superheater sections of the boiler, flow past the economiser,the dust collectors and the air preheaters before being exhausted to the atmosphere.The main feature of atmospheric fluidized bed combustion is the constraint imposed by therelatively narrow temperature range within which the bed must be operated. With coal, there is a orisk of clinker formation in the bed if the temperature exceeds 950 C and loss of combustion oefficiency if the temperature falls below 800 C. For efficient sulphur retention, the temperature oshould be in the range of 800 – 850 C.
Features of bubbling bed boilers Fluidised bed boilers can operate at near-atmospheric or elevated pressure and have theseessential features:• Distribution plate through which air is blown for fluidising,• Immersed steam-raising or water heating tubes which extract heat directly from the bed,• Tubes above the bed, which extract heat from hot combustion gas before it enters the flue duct.Circulating fluidized bed combustionCFBC technology has evolved from conventional bubbling bed combustion as a means toovercome some of the drawbacks associated with conventional bubbling bed combustion.CFBC technology utilizes the fluidised bed principle in which crushed (6-12 mm size) fuel andlimestone are injected into the furnace or combustor. The particles are suspended in a stream ofupwardly flowing air (60-70 per cent of the total air), which enters the bottom of the furnacethrough air distribution nozzles. The fluidizing velocity in circulating beds ranges from 3.7 to 9m per second. The balance of the combustion air is admitted above the bottom of the furnace assecondary air.There are no steam generation tubes immersed in the bed. The circulating bed is designed tomove a lot more solids out of the furnace area and to achieve most of the heat transfer outside thecombustion zone – convection section, water walls, and at the exit of the riser. Some circulatingbed units even have external heat exchanges.The particle circulation provides efficient heat transfer to the furnace walls and longer residencetime for carbon and limestone utilisation. Similar to pulverized coal (PC) firing, the controllingparameters in the CFBC process are temperature, residence time and turbulence.For large units, the taller furnace characteristics of CFBC boilers offer better space sorbentresidence time for efficient combustion and SO2 capture, and easier application of stagedcombustion techniques for NOx control than AFBC generators. CFBC boilers are said to achievebetter calcium to sulphur utilisation 1.5 to 1 versus 3.2 to 1 for the AFBC boilers, although thefurnace temperatures are almost the same.
CFBC boilers are generally claimed to be more economical than AFBC boilers for industrialapplications requiring more than 75-100 T per hour of steam. CFBC requires huge mechanicalcyclones to capture and recycle the large amount of bed material, which required a tall boiler.At right fluidizing gas velocities, a fast recycling bed of fine material is superim posed on abubbling bed of larger particles. The combustion temperature is controlled by the rate ofrecycling of fine material. Hot fine material is separated from the flue gas by a cyclone and ispartially cooled in a separate low velocity fludised bed heat exchanger, where the heat is givenup to the steam. The cooler fine material is then recycled to the dense bed.At elevated pressure, the potential reduction in boiler size is considerable due to the increasedamount of combustion in pressurised mode and high heat flux through in-bed tubes.A CFBC boiler could be a good choice if the following conditions are met:• Capacity of boiler is large to medium,• Sulphur emission and NOx control is important,• The boiler is required to fire low-grade fuel or fuel with highly fluctuating fuel quality.Pressurised fluid bed combustionPFBC is a variation of fluid bed technology that is meant for large-scale coal burning 2applications. In PFBC, the bed vessel is operated at pressure up to 16 ata (16 kg per cm ).The off-gas from the fluidized bed combustor drives the gas turbine. The steam turbine is drivenby steam raised in tubes immersed in the fluidized bed. The condensate from the steam turbine ispreheated using waste heat from gas turbine exhaust and is then taken as feedwater for stemgeneration.The PFBC system can be used for cogeneration or combined cycle power generation. Bycombining the gas and steam turbines in this way, electricity is generated more efficiently than inthe conventional system. The overall conversion efficiency is higher by 5 to 8 per cent.
9. IMPROVEMENT OF BOILER EFFICIENCYIn order to make the boiler more efficient, it is necessary to reduce the boiler losses:- Reducing loss due to unburnt fuelIn the present day technology of gaseous fuel combustion, it is possible to completelyremove this loss. Most of the oil firing equipments would also ensure completecombustion of the oil. In the case of solid fuels however, there is always a certainquantum of unburnt carbon found along with the residual ash.. The unburnt carbon can be significantly reduced by improving the design and operation ofcombustion equipment.The combustion of fuels improves by increasing the temperature of the fuel and air aswell as by increasing time available for combustion. By providing adequate turbulanceto the combustion air, it will allow fresh molecules of oxygen to continuously come intocontact with solid fuel particles and thereby ensure complete combustion. In order toachieve these results, we must increase the air pre-heat and the heat loading in thefurnace. Burners with high swirl numbers would improve the turbalance and assit incomplete combustion of the fuel. The admission of combustion air at appropriatelocations along the trajectory of the fuel particles would also enhance completeness ofcombustion. The reduction of this loss would therefore be posible by improving thecombustion system design. The fluidised bed combustion is a very effective method ofreducing unburnt fuel loss. Many advances have been achieved in the recent past, inthe field of fluidised bed combustion technology. Reducing dry gas lossDry gas loss is directly affected by the temperature of the outgoing flue gases, as well asthe excess air coefficient adopted. With modern combustion devices, it is possible toreduce the excess air coefficient significantly. The recommended values of excess aircoefficient for various types of combustion systems are given in table 2. The reduction offlue gas outlet temperature however, would require extra investment for additionalsurfaces in air pre heater. It should also be remembered, that fuels containing sulphurshould be dealt with carefully to avoid corrosion. Corrosion (due to sulphur in fuel) canalso be minimised by using special alloy steels for the construction of last stage heatrecovery surfaces. Thus the reduction of flue gas temperature (to increase the efficiency)
would be largely a trade off between initial capital cost and revenue savings of fuel costdue to higher efficiency. Reducing loss due to fuel moistureIt is practically not possible to bring down flue gas outlet temperature to a value below100(C. However, the loss due to sensible heat of super heating water vapour can beminimised. This can be achieved by pre-drying the fuel with separate equipments. Itwould also be possible to use boiler exhaust flue gas itself for pre-drying of fuels. Thiswould be an especially attractive proposal for high moisture fuels like lignite andbagasse. Special fluidisers and agitators can be successfully adopted in such pre-dryers.In the recent days, non-metallic air preheaters and feedwater heaters have beendeveloped to reduce outgoing flue gas temperature to values below 100(C which wouldthen improve boiler efficiency considerably. Reducing loss due to radiationThe Radiation Loss is a misnomer. This loss is due to natural convection on the insulatedsurface of the boiler. The general practice for insulation is, to design the insulated skintemperature to be 20(C) above the ambient temperature. Generally this would keep down thisloss to a value less than 200 KCAL/M2/hr. However, the insulation thickness can be reduced orincreased depending on the special site conditions. In the indoor type boilers, there is reducednatural convection and hence can economically accommodate relatively higher skintemperatures. The skin temperature of the insulated surfaces is also governed by safetyrequirements.The American Boiler Manufacturers Association have made detailed studies in the paston the quantum of Radiation Loss in boilers Leaky valves and flanges contributesignificantly to this loss. Many times soot blowing cycles are adopted carelessly in the boilerswithout proper assessment, leading to wastage of super heated steam. Soot blowing need beresorted to only when the flue gas out let temperature (for a given load) increases by more than3(C. It is also necessary to have a check on the boiler blow down. Excessive blow down withoutrelation to steam purity requirements would only waste thermal energy. The steam purityachieved, would vary with the boiler water concentration in the drum.There are many electrical drives adopted for the boiler auxiliaries. The electrical powerconsumed by these auxiliaries also require careful attention since electrical energy isbasically costlier than thermal energy. Adoption of suitable power factor correctiondevises and correct sizing of the motors would be helpful.
EMERGING BOILER TECHNOLOGYUp till the 1970s, certain high-grade fuels like oil and better quality coals were utilised in boilersfor power generation purposes. But with growing awareness of sustainable use of energy,extensive utilisation of better quality fuels has become a cause for concern.The A-PFBC (series type) technology, developed in Japan, makes use of the advantageousconditions of the raised GT temperatures and improved steam conditions while mitigatingdevelopmental loads (there is no need to develop a topping combustor).In the A-PFBC system, the gas produced in the partial gasifier (syngas) is fed to a hightemperature dry desulphuriser where syngas is desupphurised by using limestone, and then iscooled by a syngas cooler (SGC). The desulphurisation of the gas prior to cooling makes SGCatmosphere slow corrosive and enables more sensible heat of the gas to be recovered as hightemperature steam. oThe cooled gas (450 C) is subjected to strict dust removal with a cyclone, ceramic filter and isthen fed to the combustor of the gas turbine to generate power.The oxidiser plays a role not only in the combustion of unburnt carbon (char) transferred fromthe partial gasifier but also in oxidizing CaS formed in the desulphuriser into gypsum (CaSO4).The high temperature flue gas from the oxidizer is introduced into the partial gasifier; thus theheat energy (sensible heat) of the flue gas is effectively used as a heat source for the partialgasifier.Integrated coal gasification combined cycleIntegrated coal gasification combined cycle (IGCC) is a new coal-utilised power generationtechnology that achieves higher thermal efficiency and better environmental performance for thenext generation.IGCC uses a combined cycle format with a gas turbine driven by the combusted syngas, whilethe exhaust gases are heat exchanged with water/ steam to generate superheated steam to drive asteam turbine. Using IGCC, more of the power comes from the gas turbine. Typically 60 – 70per cent of the power comes from the gas turbine with IGCC, compared with about 20 per centusing PFBC.Coal gasification takes place in the presence of a controlled “shortage‟ of air/oxygen, thusmaintaining reducing conditions. The process is carried out in an enclosed pressurised reactor,and the product is a mixture of CO and H2 (called synthesis gas, syngas or fuel gas). The productgas is cleaned and then burnt with either oxygen or air, generating combustion products at hightemperature and pressure. The sulphur present mainly forms H2S but there is also a little COS.The H2S can be more readily removed than SO2. Although no NOx is formed during gasification,some is formed when the fuel gas or syngas is subsequently burnt.