Patel dhaval

A Project Report On

PROBLEMS IN BOILER LIKE EFFIENCY,MAINTENANCE AND SAFETY.

Submitted in partial fulfillment ofthe requirements for the degree of

Bachelor of Engineering

Submitted byPatel 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 Guide Asst. 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 institutions

Junagadh

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 institutions

Junagadh

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 escape with what little sanity remains. I would like to thank Mr. Hiral badrakia, our advisor for the duration, for supporting us during our time. He has provided direction and opinion grounded in the reality that we all too often allow to pass by the wayside in our quest for solutions. He has also been a friend and mentor and We sincerely hope we find opportunities in the future to work together once again. We would also like to extend my thanks to Mr. Haridas Krisnan, the man who has taught us the importance of written and oral communication skills in the engineering profession. Further, his outlook on life has been inspiring and at times, frightening. He, above all, exemplifies the importance maintaining a realistic opinion of the importance of your work; it keeps you honest.

PREFACE`

The mechanical engineering is well structured and integrated course of engineering studies. The main objective of Industrial Define Problem (IDP) is to develop skill in student by

supplement to the theoretical study. Industrial training helps to gain real life knowledge about the industrial environment, manufacturing practices and to develop skill about industrial problem.

In every professional course, IDP is an important factor. Professors give us theoretical knowledge of various subjects in the college but we are practically exposed of such subjects when we get the project in the organization. It is only the project through which I come to know that what an industry is and how it works and how to problem can be solved. I can learn about various departmental operations being performed in the industry, which would, in return, help me 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 the manufacturing process and industrial problems in real that how it differs from those of theoretical 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, which would help an individual in my carrier activities and it is true that

“Experience is best teacher”.

Patel HardikPatel Dhaval

Patel Nishit

INDEX1. INTRODUCTION

1.1 BOILER SPECIFICATION1.2 BOILER SYSTEM

2. BOILER TYPES AND CLASSIFICATIONS

3. FEATURE OF PACKAGE BOILER

3.1 CHAIN GRATE FOR TRAVELLING GRATE STROKER BOILER.

4. DEFINING BOILER EFFICIENCY 4.1 BOILER TERMINOLOGY

5. 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 LEVEL10.3 BLOWDOWN10.4 LOW WATER FUEL CUT OUT 10.5 BOILER WATER TREATMENT10.6 MAINTANANCE OF STEAM PIPES10.7 CHARACTERISTICS OF STEAM STRAP FAILURE

11. MAIINTAINING BOILER SAFETY11.1 SAFETY11.2 BOILER FAILURE11.3 POOR FEED WATER QUALITY11.4 IMPROPER BLOWDOWN11.5 STEAM BOILER FAILURE11.6 COMMON CAUSESS OF FUEL EXPLOSION11.7 STEAM BOILER FAILURE11.8 BOILER SAFETY OPERATION AND MAINTANACE AND PRACTISES

12. CONCLUSION13. REFERENCE

1. Introduction Boiler is A an enclosed vessel that provides a means for combustion heat to be transferred into water until it becomes heated water or steam. The hot water or steam under pressure is then usable for transferring the heat to a process. Water is a useful and cheap medium for transferring heat to a

process. When water is boiled into steam its volume increases about 1,600 times, producing a force that is almost as explosive as gunpowder. This causes the boiler to be extremely 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 is transferred from one body to another by means of (1) radiation, which is the transfer of heat from a hot body to a cold body without a conveying medium, (2) convection, the transfer of heat by a conveying medium, such as air or water and (3) conduction, transfer of heat by actual physical contact, molecule to molecule.

Boiler Specification

The heating surface is any part of the boiler metal that has hot gases of combustion on one side and water on the other. Any part of the boiler metal that actually contributes to making steam is heating surface. The amount of heating surface of a boiler is expressed in square meters. The larger the heating surface a boiler has, the more efficient it becomes. The quantity of the steam produced is indicated in tons of water evaporated to steam per hour. Maximum continuous rating is the hourly evaporation that can be maintained for 24 hours. F & A means the amount of

steam generated from water at 100oC to saturated steam at 100 oC

BOILER SYSTEMS

The boiler system comprises of: feed water system, steam system and fuel system. The feed water system provides water to the boiler and regulates it automatically to meet the steam demand. Various valves provide access for maintenance and repair. The steam system collects and controls the steam produced in the boiler. Steam is directed through a piping system to the point of use. Throughout the system, steam pressure is regulated using valves and checked with steam pressure gauges. The fuel system includes all equipment used to provide fuel to generate the necessary heat. The equipment required in the fuel system depends on the type of fuel used in the system. The water supplied to the boiler that is converted into steam is called feed water. The two sources 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 plant processes. For higher boiler efficiencies, the feed water is preheated by economizer, using the waste 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

limited generally to capacities of 25 tons/hr and pressures of 17.5 kg/cm2. 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 convection

Water 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 of grate. The main classifications are:

1. Chain-grate or traveling-grate stoker

2. Spreader stoker

Chain-Grate or Traveling-Grate Stoker Boiler

Coal is fed onto one end of a moving steel chain grate. As grate moves along the length of the furnace, 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 combustion leaving 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 to control the rate at which coal is fed into the furnace, and to control the thickness of the coal bed and speed of the grate. Coal must be uniform in size, as large lumps will not burn out completely by the time they reach the end of the grate. As the bed thickness decreases from coal-feed end to rear 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 Efficiency

Boiler 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 Terminology

MCR: 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 efficiency

Combustion efficiency is the effectiveness of the burner only and relates to its ability tocompletely burn the fuel. The boiler has little bearing on combustion efficiency. A well designed burner 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 air levels of 15% and result in negligible unburned fuel. By operating at only 15% excess air, less heat from the combustion process is being used to heat excess air, which increases the available heat for the load. Combustion efficiency is not the same for all fuels and, generally, gaseous and liquid fuels burn more efficiently than solid fuels.

Thermal efficiency

Thermal 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 efficiency

The 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 efficiency

Fuel 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. Thefirst method is input output method. The second method is heat loss method.Fuel-to-steam efficiency is a measure of the overall efficiency of the boiler. It accountsfor the effectiveness of the heat exchanger 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 the

fuel-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 EFFICENCY

CALCULATION

1) 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 between

losses 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) / 2257

The 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 m2

Where, m is the actual mass of water evaporated in kg

The Direct Method

This 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/kgIf 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 efficiency

Economizer 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 efficiency

Super 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 figures

Disadvantages

• No explanation of low efficiency• Various losses not calculated

The Indirect Losses Method

The 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 Efficiency

The 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 higher efficiency .

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 the capital cost goes up. Thetechnology has been proven and demonstrated since the 1950s. The problemswere severe superheater material wastage, unacceptable creep, and thermalfatigue cracking experienced when metal temperatures exceededapproximately 1,025°F.1 The issue was corrosion and strength at these extreme conditions.

Heat integration represents another trade off. Rather than transferring cooling water to a process stream that needs to be cooled down and steam to another process stream that needs to be heated up, the work can be partially accomplished by bringing the two streams into thermal contact via a heat exchanger.

There is a significant efficiency benefit, but process-process heat exchangers can cause operational problems, especially during transient phases and in the event of fouling or fluid leakage across the exchanger. Thus heat integration represents a trade off between efficiency and availability. Unit role, peaking, base loading, etc, affect design and operational practices of using units for a role other than which they were designed. Old base load design units are often used for 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 heat integration systems, staying after steam leaks and exchanger fouling, and a large number of other practices. Operating at full load capacity continuously will enhance efficiency. However the reality is that load is ever changing and the requirements of market based systems focus on reliability 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 and less water. However additional coal production is largely focused on the Powder River Basin which is sub-bituminous.

Pollutant control

. The level of pollutant emission control (including thermal) effects efficiency. NOx reduction units and SOx scrubbers represent parasitic loads that decrease net generation and thus reduce efficiency.

6. IMPROVING ENERGY EFFICIENCY OF BOILER SYSTEMS

When considering boiler energy savings, invariably the discussion involves the topic of boiler efficiency.

The boiler suppliers and sales personnel will often cite various numbers, like the boiler has a thermal 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 less fuel in the same application! The trouble is that there are several norms to determine the efficiencies figures and it is practically very difficult to verify these without costly test procedures. The easiest and most cost effective method is to review the basic boiler design data and 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 has two 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 the fuel is to be recovered, including latent heat. In most equipment, this is not so the case, and the calculations of efficiency based on gross calorific value will give maximum obtainable efficiencies much lower than 100%, due to this irrecoverable loss.

Both the gross calorific value and net calorific value are equally valid, but for comparison purposes, 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 understand efficiency values more thoroughly. An important thing to note is to make the comparisons on equal footings.

COMBUSTION EFFICIENCY The 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 smoke characteristics is the first early indicators of potential combustion related problems. But in practice, combustion efficiency is verifiable only with a flue gas analyzer. The stack temperature and flue gas oxygen (or excess air) concentrations are primary indicators of combustion efficiency.

The Logic of Combustion Efficiency Tests

The “combustion efficiency” test determines how completely the fuel is burned, and how effectively 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 these conditions. The test is essentially a test for excess air, combined with a flue gas temperature measurement.

Excess Air

The only purpose of bringing air into the boiler is to provide oxygen for combustion. Bringing in too 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. The temperature 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. In practice, combustion conditions are never ideal, and additional or “excess” air must be supplied to completely burn the fuel. When the air falls below the stoichiometric value, there is some fuel that is not burned completely. This partially burned fuel creates smoke, leaves deposits on firesides, and creates environmental problems. Unburned fuel may also represent a significant waste of energy. The amount of waste depends on the energy content of the unburned fuel

Excess Air V/s Boiler Efficiency The table below relates the O2 levels to the excess air and combustion efficiency when seen

together with stack temperatures.

On well designed natural gas-fired systems, an excess air level of 10% is attainable and for fuel oil system 15% is a reasonable figure.

An often stated rule of thumb is that 100% excess air reduces the boiler efficiency by 5% or boiler 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 150 psig steam. Stack gas measurements indicate an O2 level of 7% corresponding to an excess air

level of 44.9% and with a flue gas less combustion air temperature of 400°F.

Solution

The cost savings shall be provided by equation:

Cost Savings = Fuel Consumption x (1 – Eff. Initial /Eff. Tune up) x steam cost

From the table, the initial boiler combustion efficiency is 78.2% and after tune-up the boiler combustion efficiency increases to 83.1%. Therefore:

Cost Savings = 55 x (1 – 78.2/83.1) x 5 = $ 16.2 per hour

Or the cost savings will be $129,600 per annum for 8,000 hours of operation per year.

Optimum Excess Air

Fuel Type Minimum + Excess recommended

= Total O2

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 heating surface, 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 burner linkage design or does not include a high-quality air damper arrangement, it is questionable that it 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 the greater 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 Air

Proceeding 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 CO2 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 fairly

low level at high excess air, but rises sharply as excess air is reduced below the optimum level.

Flue gas Analysis - What to measure, O 2 or CO2?

Flue gases contain a composition of oxygen, carbon dioxide, carbon monoxide and sulfur dioxide. All of these gases are easily detectable with modern instrumentation. Oxygen monitoring 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 relative change in oxygen is much greater than the relative change in carbon dioxide for a given change in excess air. For example, with No. 2 oil, an increase in excess air from 2% to 10% causes oxygen in the flue gas to increase by a factor of five, a change that you can measure easily. On the other hand, the same increase in excess air causes carbon dioxide to drop by only 10%, a difference that is more difficult to measure accurately.

Another advantage of the oxygen test is that the results are much less sensitive to variations in the chemical composition of the fuel. The amount of carbon dioxide in the flue gas depends on the amount of carbon in the fuel, and the amount of excess air is calculated from this carbon dioxide value. There are large differences in the chemical composition of some fuels, such as industrial 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 carbon content do not affect the results of the oxygen test at all, and variations in the total energy content of the fuel affect the oxygen content much less than they affect the carbon dioxide content.

Unlike the carbon dioxide test, the oxygen test works only in the region of excess air. There is no oxygen to measure when there is no excess air. This is not a problem in normal testing, because you should always operate boilers with a small amount of excess air.

Additional Tests for Incomplete Combustion

To fine-tune the excess air, you may need an additional test that detects small amounts of incompletely burned combustion products. Two common tests for this purpose are smoke density and carbon monoxide in the flue gas.

Carbon Monoxide Test

The carbon monoxide content of flue gas is a good indicator of incomplete combustion with all types of fuels, as long as they contain carbon. Carbon monoxide in the flue is minimal with ordinary amounts of excess air, but it rises abruptly as soon as fuel combustion starts to be incomplete. 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 ratio indicates trouble within the boiler. Carbon monoxide rises excessively if any defect in the boiler causes incomplete combustion, even with excess air. This makes carbon monoxide testing an excellent 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 might also point toward a more subtle problem, such as a poor match of the burner assembly to the firebox, causing a portion of the flame to strike a surrounding surface. (Cooling the flame interrupts the combustion process, leaving carbon monoxide and other intermediate products of combustion in the flue gases.)

Carbon monoxide also forms if there is a great excess of air. This is not a matter of practical significance. Once you set the air-fuel ratio properly, the carbon monoxide content falls into the proper range if there are no other problems.

Approach to Optimum Combustion Control Usually the cause of excessive or deficient combustion is:

1) The Draft

2) Proper Air-Fuel Mix

Draft Control

The major cause of boiler losses, both avoidable and unavoidable, is the boiler draft. Poor draft conditions alters the flame pattern thus inhibiting the fuel from burning properly and changing the 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 or properly controlled. Strong consideration should be given to installing a forced draft system under this situation. Even with a forced draft system, it still may not be feasible to closely regulate 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 problem

with the furnace draft. In these situations, the manufacturer’s representative should be consulted to discuss upgrading the controls and equipment.

Air-Fuel Ratio

The efficiency of the boiler depends on the ability of the burner to provide the proper air to fuel mixture 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 be taken 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 should therefore compensate for seasonal temperature variations and, optimally, for day and night

Effects of Air Temperature on Excess Air Level

Usually the cause of improper Air-Fuel ratio is due to inadequate tolerance of the burner controls, a faulty burner or improper fuel delivery other than draft conditions. Often, the burner cannot 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 substantial dollars every time you fire the unit.

If you are unable to maintain the CO levels < 400 ppm, it indicates the poor mixing of fuel and air at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization of burner nozzle and deterioration of diffusers or spinner plates.

Excess Air Control - Control & Automation

Excess air control (also referred to as O2 control) is important for optimum combustion and can

be 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 is as 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 Systems Every 1% decrease in excess O2 from the stack, results in as much as ½ % increase in thermal

efficiency.

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. The oxygen “trim” system provides feedback to the burner controls to automatically minimize excess combustion air and optimize the air-to-fuel ratio. It increases energy efficiency by one to two percent. For very large boilers, efficiency gains of even 0.1 percent can result in significant annual savings.

The use of O2 trim, only trims the amount of excess air above that required for complete

combustion for a specific furnace design while not creating a fuel-rich furnace/stack environment. The burner design, fuel selection and load swing are all critical factors affecting the decision to O2 trim in any given boiler.

Unfortunately, high cost of purchasing and installing an oxygen analyzer discourage its use to small 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 appropriate to 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 boiler's 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 Combustion

The 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 world today. Unburned hydrocarbons, carbon monoxide, carbon dioxide, sulfur oxides & nitrogen oxides 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, the burners or the design of the boiler. Inaccuracies on measurements due to stratification might occur with sample type sensors but essentially flue gas CO concentration is unaffected by air infiltration, 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, and

falls off both with increasing and with decreasing excess air. Therefore, applying energy efficiency 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 reactions

of N2 at high temperatures.

Emissions of SO2 and NOx contribute to acid rain and condensation of these products inside the

stack may lead to corrosion of chimney.

SO2 emissions can be controlled by limiting the allowable sulfur content of the fuel and NOx emissions can be reduced by manipulating the combustion process.

Managing combustion processes better and improving the efficiency of energy use & generation are two of the key strategies for reducing atmospheric emissions.

Keeping boiler clean from soot Under conditions of incomplete combustion, unburnt carbon particles get deposited in the form of soot on the inside of fire tubes.

Except for natural gas, practically every fuel leaves a certain amount of deposit on the fireside of the 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 a 4.5 mm (0.18 in.) layer by 69 percent. As the layer of soot builds up, the stack temperature rises by about 100°F for 1mm thick soot coating. For every 40°F rise in stack temperature, boiler efficiency 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 occur due to the melting of some of the components of the deposits having a low melting point. Also in the heat recovery system like an economizer or preheater, corrosion due to sufhur trioxide may show up. Periodic off-line cleaning of radiant furnace surfaces, boiler tube banks, economizers and air heaters may be necessary to remove these stubborn deposits.

Large boilers and those burning fuels with a high fouling tendency have strategically located soot blowers as in integral part of the boiler. Soot blowers are machines that mechanically drive bushes or scrapers through the tubes and clean the surfaces while the boiler is operating. These machines, 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 the deposition. The cleaning can be handled using portable powerful air motors, which drive flexible shafts fitted with a wide variety of cleaning tools.

Energy Loss due to Improper De-aeration of Boiler Feedwater

Since makeup water contains considerable amounts of dissolved oxygen, corrosion becomes a critical reliability concern because high heat intensity at the boiler tubes accelerates the oxidation process. 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 transfer by up to 50%. Therefore, attention to the de-aeration process as well as to the proper functioning of air vents is of significant importance.

Deaerator is most commonly used equipment to get rid of dissolved oxygen. Very briefly, the deaeration process uses live steam to bring the feedwater up to approximately 105°C and mechanical agitation to drive off the oxygen from the water. The liberated dissolved oxygen must be continuously removed from the deaerator, and hence, a small amount of purge steam from the deaerator is an accepted industrial norm.

The size of this required purge depends on factors like design capacity, efficiency and oxygen loading on the deaerator unit. Typically, the vent rate is around 0.5 to 1% for smaller, more efficient units and having lower make-up water. High make-up water requires vent rate of over 1%.

Example: A boiler with 100,000 lb/hr capacity vent out 1,000 lb/hr of steam. That amounts to 8 million pounds of steam per year costing $64,000.00 at $8.00 per thousand pounds. Additional venting 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 to the required levels. Note that the higher the makeup water, the higher is the dissolved oxygen loading. 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 left behind in the boiler water. Fresh makeup water enters the boiler to replace the amount lost through steam evaporation. When this new water is converted to steam, more solids are left behind. As steam is continually produced, evaporated, and replaced with new water, the amount of solids in the boiler continues to increase indefinitely until the water is unable to dissolve its own impurities or hold them in solution. These will inevitably collect in the bottom of the boiler in 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 in the water will have doubled when the amount of new water that has entered the boiler is equal to the amount of water that was used to originally fill the boiler. When the amount of solids has doubled, 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 Blowdown Insufficient blowdown may lead to carryover of boiler water into the steam, or the formation of deposits. Excessive blowdown will waste energy, water, and chemicals. The optimum blowdown rate is determined by various factors including the boiler type, operating pressure, water treatment, and quality of makeup water. Blowdown rates typically range from 4% to 8% of boiler feedwater flow rate, but can be as high as 10% when makeup water has high solids content.

For example, consider a 50,000 lb/hr boiler operating @ 125 psig has a blowdown heat content of 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, worth about $42,000 per year based on 8,000 hrs of operation per year at $5 per 1,000 cu-ft.

Blowdown Calculations

The quantity of blowdown required to control boiler water solids concentration is calculated by using the following formula:

If maximum permissible limit of TDS as in a package boiler is 3,000 ppm, percentage make up water 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 Test Chloride 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 produced

If 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 5 cycles 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 the boiler sight glass. When the Chloride reading of the boiler water is 6 times the Chloride reading of the raw water, there are 6 cycles of concentration.

Specific Conductance Test

The second test used for regulating blowdown is specific conductance. A conductivity meter is used to measure the conductivity of the "make up" water as compared to the conductivity of the boiler 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 2100 umhos, 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 and respond to boiler water conductivity much more effectively.

Energy Savings due to Reduction in Blowdown

Assuming the feedwater consists of 60% returned condensate and 40% makeup water; the analyzed 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 lower blowdown 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 proportionately reduced by 1.7% from 10 to 8.3 percent.

Actual blowdown and feedwater requirements for steam production of 100,000 lb/day are calculated by using several formulas:

F = E / (1- B)

Consequently, returning 7% more condensate of the boiler realizes a fuel savings of $21,504 per annum assuming 350 days operation.

Blowdown Heat Recovery

Although reducing blowdown results in substantial fuel savings, this function cannot be eliminated entirely. A boiler operating on high quality feedwater needs very little blowdown, while equipment using feedwater containing solids, alkalinity or silica requires a much higher rate, may be even continuous discharge.

Flash Steam Recovery

Flash steam heat recovery is a method for recovering at least 85% of the blowdown heating value.

About half of the heat contained in the blowdown water is recovered in the form of flash steam by discharging the flow to a flash tank, usually operated at 5 psig. A portion of the blowdown flashes to steam at the lower pressure and is available for use in the deaerator or for other low pressure demands.

Flash steam recovery is calculated using the formula:

A = (H – W) / L

Where:

• 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/lb

Assuming, a flash tank is added to a boiler operating at 235 psig and generating 1,000,000 lb/day of steam, the blowdown rate is 5%, or 52,632 lb/day

A = (376 – 196) / 960

A = 0.1875 or 18.75%

Daily heat recovery is calculated by applying the formula

G = A x J x K

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/lb

Using the numbers

G = 0.1875 x 52,632 x 1156

= 11,407,986 Btu/day

Blowdown heat recovery

Heat exchangers can reclaim the sensible heat from the blowdown that goes into sewerage for heating boiler makeup water and the like.

In most cases, the heat exchanger is designed to reduce the temperature of the blowdown water to 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, Btu

P = Water heat content at exchanger outlet, Btu/lb

M = 52,356 x (1- 0.1875) x (196-48)

M = 6,296.531 Btu/day

Total 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 two methods captured 89% of the blowdown water energy.

Optimum Pipe Sizing Steam piping transports steam from the boiler to the end-use services whereas condensate return piping transports condensate back to the boiler. Important characteristics of well-designed steam & condensate system piping are these that are adequately sized, configured, insulated and supported.

The steam flow through the pipe in terms of pressure and volume required is dictated by the process needs. Proper sizing of steam pipelines help in minimizing pressure drop. There are broad limits on the velocities of steam in pipes imposed by considerations of related erosion rates etc. 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/sec

Velocities exceeding these are likely to generate noise and erosion, specifically if there is wet steam. For shorter branch connections, it is advisable not to exceed 15 m/s. The starting

conditions 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 number and the relative roughness of the pipes internal surface, defined as the ratio of a mean roughness height ‘k’ to the pipe diameter. For commercial, non-corrosive steel tubes commonly used in steam and water service, k may be taken to be 0.05 mm. As the network in general will include tees, bends, valves etc, these will also contribute to overall friction.

Standard data tables are available that help in making the final selection. The equations, on which 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 pipes require 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 rest of the system; the heat loss per length of pipe remains the same. The heat losses from extra piping 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 and low cost opportunity to save energy and money.

d) Install meters and keep track of where the steam is going. The facility-wide and individual process-unit steam balances will help in accessing losses in a better way.

e) Important configuration issues are flexibility and drainage. With respect to flexibility, piping especially at equipment connections, needs to accommodate thermal reactions during system startups and shutdowns. With respect to drainage, the piping should be equipped with a sufficient number 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 for every 30 meter length. The piping should be pitched properly to promote the drainage of condensate to these drip lines. Typically these drainage points experience two very different operating conditions: normal operation and startup. Both load conditions should be considered in the initial design.

g) Drain points should be provided at intervals of 30 to 45 meters along the main. Drain points should also be provided at low points in the mains and where the steam main rises. Ideal locations 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 preferable to 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 branch line itself will act as a drain for the condensate.

j) Expansion loops are required to accommodate the expansion of steam lines while starting from cold.

k) To ensure dry steam in the process equipment and in branch lines, steam separators can be installed as required.

Proper Insulation Of Steam Pipe

Important 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 of insulation varies with temperature; consequently, it is important to know the right temperature range when selecting insulation. In general, the lower the thermal conductivity, the higher will the 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 maintenance tasks.

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 heat of 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-air mixture, thus dropping the overall temperature of the steam-air mixture, which is the heating media. It is however, impossible to avoid the entry of air into a steam system that is working intermittently. If the steam condenses during the shut downs, air tends to be sucked in due to the partial vacuum created. Air is also pushed into the process equipment from the steam mains at the time of start up. The situation can be improved by installing properly sized air vents 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 thermostatic steam traps) should be fitted above the condensate level so that only air or steam-air mixtures can reach them.

8. Boiler Technologies

Boiler technology the world over has evolved vastly over the years. From the conventional pulverized coal boilers to fluidised bed combustion technology and multi-fuel firing boilers, the industry has indeed come a long way.

This write-up describes the available and emerging technology options, their benefits and limitations.

CURRENT TECHNOLOGIES

Pulverised fuel boiler is the most commonly used method in thermal power plants, and is based on many decades of experience. Units operate at close to atmospheric pressure, simplifying the passage of materials through the plant.

Most coal-fired power station boilers use pulverised coal, and many of the larger industrial watertube boilers also use this fuel. This technology is well developed, and there are thousands of 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 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 1,300 to 1,700

oC, depending largely on coal grade. Particle residence time in the boiler is typically two to five 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 the ability to fire varying qualities of coal, quick responses to changes in load, use of high preheat air temperatures, etc. Pulverised coal boilers have been built to match steam turbines, which have outputs of between 50 and 1,300 Mwe. In order to take advantage of the economies of scale, most new units are rated at over 300 Mwe, but there 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 distribution system if they should “trip out” for any reason, or be unexpectedly shut down.

Fluidised bed combustion

Fluidized bed combustion has emerged as a viable alternative and has significant advantages over the conventional firing system and offers multiple benefits. Some of the benefits are compact boiler design, fuel flexibility, higher combustion efficiency and reduced emission of noxious pollutants such as SOx and NOx. The fuels burnt in these boilers include coal, washery

rejects, rice husk, bagasse and other agricultural waste. Fluidised bed boilers have a wide capacity 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 bed

In AFBC, coal is crushed to a size of 1-10 mm depending on the rank of coal, and type of fuel fed into the combustion chamber. The atmospheric air, which acts as both the fluidisation air and combustion air, is delivered at a pressure and flows through the bed after being preheated by the exhaust flue gases. The velocity of fluidizing air is in the range of 1.2 to 3.7 m per second. The rate 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 depth is usually 0.9 m to 1.5 m and the pressure drop averages about 1 inch of water per inch of bed depth. Very little material leaves the bubbling bed-only about 2 to 4 kg of solids are recycled per kg 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 the relatively narrow temperature range within which the bed must be operated. With coal, there is a

risk of clinker formation in the bed if the temperature exceeds 950 oC and loss of combustion

efficiency if the temperature falls below 800 oC. For efficient sulphur retention, the temperature

should be in the range of 800 – 850 oC.

Features of bubbling bed boilers

Fluidised bed boilers can operate at near-atmospheric or elevated pressure and have these essential 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 combustion

CFBC technology has evolved from conventional bubbling bed combustion as a means to overcome 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 and limestone are injected into the furnace or combustor. The particles are suspended in a stream of upwardly flowing air (60-70 per cent of the total air), which enters the bottom of the furnace through air distribution nozzles. The fluidizing velocity in circulating beds ranges from 3.7 to 9 m per second. The balance of the combustion air is admitted above the bottom of the furnace as secondary air.

There are no steam generation tubes immersed in the bed. The circulating bed is designed to move a lot more solids out of the furnace area and to achieve most of the heat transfer outside the combustion zone – convection section, water walls, and at the exit of the riser. Some circulating bed units even have external heat exchanges.

The particle circulation provides efficient heat transfer to the furnace walls and longer residence time for carbon and limestone utilisation. Similar to pulverized coal (PC) firing, the controlling parameters in the CFBC process are temperature, residence time and turbulence.

For large units, the taller furnace characteristics of CFBC boilers offer better space sorbent residence time for efficient combustion and SO2 capture, and easier application of staged

combustion techniques for NOx control than AFBC generators. CFBC boilers are said to achieve

better calcium to sulphur utilisation 1.5 to 1 versus 3.2 to 1 for the AFBC boilers, although the furnace temperatures are almost the same.

CFBC boilers are generally claimed to be more economical than AFBC boilers for industrial applications requiring more than 75-100 T per hour of steam. CFBC requires huge mechanical cyclones 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 a bubbling bed of larger particles. The combustion temperature is controlled by the rate of recycling of fine material. Hot fine material is separated from the flue gas by a cyclone and is partially cooled in a separate low velocity fludised bed heat exchanger, where the heat is given up 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 increased amount 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 combustion

PFBC is a variation of fluid bed technology that is meant for large-scale coal burning

applications. In PFBC, the bed vessel is operated at pressure up to 16 ata (16 kg per cm2).

The off-gas from the fluidized bed combustor drives the gas turbine. The steam turbine is driven by steam raised in tubes immersed in the fluidized bed. The condensate from the steam turbine is preheated using waste heat from gas turbine exhaust and is then taken as feedwater for stem generation.

The PFBC system can be used for cogeneration or combined cycle power generation. By combining the gas and steam turbines in this way, electricity is generated more efficiently than in the conventional system. The overall conversion efficiency is higher by 5 to 8 per cent.

9. IMPROVEMENT OF BOILER EFFICIENCY

In order to make the boiler more efficient, it is necessary to reduce the boiler losses:-

Reducing loss due to unburnt fuel

In 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 of combustion 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 loss

Dry 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 moisture

It 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 radiation

The '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 this loss to a value less than 200 KCAL/M2/hr. However, the insulation thickness can be reduced or increased depending on the special site conditions. In the indoor type boilers, there is reduced natural convection and hence can economically accommodate relatively higher skin temperatures. The skin temperature of the insulated surfaces is also governed by safety requirements.

The American Boiler Manufacturers' Association have made detailed studies in the paston the quantum of 'Radiation Loss' in boilers Leaky valves and flanges contribute significantly to this loss. Many times soot blowing cycles are adopted carelessly in the boilers without proper assessment, leading to wastage of super heated steam. Soot blowing need be resorted to only when the flue gas out let temperature (for a given load) increases by more than 3(C. It is also necessary to have a check on the boiler blow down. Excessive blow down without relation to steam purity requirements would only waste thermal energy. The steam purity achieved, 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 TECHNOLOGY

Up till the 1970s, certain high-grade fuels like oil and better quality coals were utilised in boilers for 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 advantageous conditions of the raised GT temperatures and improved steam conditions while mitigating developmental 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 high temperature dry desulphuriser where syngas is desupphurised by using limestone, and then is cooled by a syngas cooler (SGC). The desulphurisation of the gas prior to cooling makes SGC atmosphere slow corrosive and enables more sensible heat of the gas to be recovered as high temperature steam.

The cooled gas (450oC) is subjected to strict dust removal with a cyclone, ceramic filter and is then 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 from the 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 the heat energy (sensible heat) of the flue gas is effectively used as a heat source for the partial gasifier.

Integrated coal gasification combined cycle

Integrated coal gasification combined cycle (IGCC) is a new coal-utilised power generation technology that achieves higher thermal efficiency and better environmental performance for the next generation. IGCC uses a combined cycle format with a gas turbine driven by the combusted syngas, while the exhaust gases are heat exchanged with water/ steam to generate superheated steam to drive a steam turbine. Using IGCC, more of the power comes from the gas turbine. Typically 60 – 70 per cent of the power comes from the gas turbine with IGCC, compared with about 20 per cent using PFBC.

Coal gasification takes place in the presence of a controlled “shortage’ of air/oxygen, thus maintaining 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 product

gas is cleaned and then burnt with either oxygen or air, generating combustion products at high temperature 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.

The IGCC demonstration plants use different flow sheets, and therefore test the practicalities and economics of different degrees of integration. As with PFBC, the driving force behind the development is to achieve high thermal efficiencies together with low levels of emissions.

Supercritical boiler

The earliest supercritical boilers were built in the US in the late 1950s and early 1960s. Designed to operate above steam’s critical pressure of 3208 psi, these early units developed a reputation for high thermodynamic efficiency (around 35 per cent, based on lower heating value-LHV) but low reliability.

The materials of that era, plant owners came to realise, were simply not up to the temperature and pressure challenges, and the North American industry put supercritical technology “on the backburner”. The ascent of gas-fired combined cycles continued to suppress interest in the technology in this region.

In Europe and Asia, however, supercritical technology continued to be pursued, and by the 1990s it had come to dominate new capacity projects. The capital cost of supercritical technology is slightly higher than subcritical, but fuel savings and environmental advantages can tip the scale.

Compared to the 1950s designs, steam pressures in most of these units have increased well into the supercritical range – up to 4,500 psig- although steam temperatures were maintained around

the same 1,000 oF limit. The result was a thermal efficiency of approximately 40 per cent (LHV).

More advanced designs introduced in the late 1990s have raised steam temperature as high as

1,150 oF, achieving efficiencies of 44 per cent. And main steam conditions above 1,200 oF are foreseen, which should yield an efficiency approaching 50 per cent. The increase in efficiency not only reduced fuels cost, but also specific (per MW) emissions of NOx and SO2, as well

overall emission of CO2, compared to sub critical coal-fired boilers.

All supercritical boilers are of a once through arrangement, meaning that water and steam flow through the boiler circuitry only once. Contrast this with drum boilers, in which water and steam recirculate through the furnace enclosure. The major difference between the various once-through boiler technologies in the market is the configuration of the furnace enclosure circuits and in the system used to circulate the water through those circuits during start-up and at lower loads.

10. Boiler Operation and Maintenance

Maintenance Basics

The boiler operator is responsible for operating and maintaining the boiler in a safe and efficient manner through the use of sound engineering practices and manufacturer’s specified maintenance procedures. Most boiler accidents are caused by operator error and poor maintenance.The Chief Engineer of a boiler plant holds the responsibility for directing boiler operations, procedures and maintenance.The information used by the Chief Engineer comes from manufacturer’s recommendations, the ASME and NBIC codes, and generally accepted maintenance practices.Log sheets are a paper record of boiler operation and maintenance, and should be used in all boiler rooms to help ensure safe operation. A log sheet will specify the task to be performed, such as blowing down the low water cut-out (LWCO), and the operator can then mark the sheet to show that this operation was completed.

General Boiler Operations include:

• Startup

Cold iron start up and new plant start up. Most furnace explosions occur during start up and when switching fuels, so always follow the manufacturer’s guidelines.

• Operation & General Maintenance

requires proper training, equipment familiarity and routine maintenance procedures.

• Shutdown

Whether for a short time or long time, different procedures exist. If the boiler is to be placed out of service for an extended period of time, proper lay-up procedures are required and must be followed.

Normal Operating Water Level

The most important task in boiler maintenance is maintaining the normal operating water level (NOWL) in the boiler. A low water condition is the most common cause of boiler failure. The first thing a boiler operator should do when entering the boiler room or taking over boiler operation is to check the NOWL. An automatic boiler feedwater regulator is designed to maintain the proper water level in the boiler. A low water alarmin the system is designed to alert the boiler operator of a low water level. In the event of a low water alarm, secure the fire first before adding water to the boiler. The gage glass (sight glass) is a tube that indicates the water level in the boiler. It is installed either directly on the boiler or on the water column. It is connected at the top into the steam section of the boiler and at the bottom into the water section, thus showing the true boiler water level. The water level in the gage glass is tested by opening and then closing the gauge glass blowdown valve. In addition to the gage glass, some boilers also have try-cocks installed to indicate the water level. The three try-cocks (which are drain valves) are placed on the water column at various levels. If the boiler water level is at the NOWL, the bottom try-cock will vent water, the middle try-cock will vent water/steam, and the top try-cock will vent steam.

Blowdowns

Boiler blowdown is removal of water from the boiler. It is done in order to remove the amount of solids in the water, andis performed as either bottom (sludge) blowdown, or continuous (surface) blowdown. The blowdown frequency andduration is primarily determined by the boiler water analysis. The water quality will vary greatly based on boiler type andsize, amount of condensate return, and boiler water treatment program.

Inspections

A boiler internal inspection is performed to allow the boiler inspection a view of all internal surfaces, i.e. tubes, shell,drum, welds, refractory, etc. The boiler is taken off line, cooled,

drained, opened and cleaned in preparation for the internal boiler inspection. All hand holes and manholes are opened, and the low water cut-outs are opened and cleaned.An external inspection can be performed by• Viewing the outside of the boiler while operating• Viewing the outside of the boiler while shut down but not open• Hydrostatic inspection or Operational inspection which is performed while the boiler is on line. This is a waterpressure test of new installations and repaired boilers.A handhole provides access to the waterside of the firetube boiler for inspection.

Boiler trim, Valves, Fittings, and Controls

Boiler trim is the controls and fittings used to operate the boiler. The trim determines whether the pressure vessel is used for steam or hot water production. Trim includes devices such as the low water cut-out, the gage glass (sometimes called the sight glass), the pressure gauge, etc.

Valves

The safety valve (also referred to a relief valve, pop-off valve, or safety relief valve) provides protection to the pressure vessel from over pressurization and is the primary safety control on all boilers. Safety valves are designed and installed in accordance with ASME and NBIC code. They must be of sufficient size (capacity) to keep the boiler from developing moresteam pressure than the valve can relieve, and must be set at or below the boiler MAWP (Maximum Allowable Working Pressure). Valve pressure settings cannot be changed by plant personnel, but must be calibrated by a certified repair facility. There should be no shut off valves between the boiler and the pop-off valve. Boilers with more than 500 sq ft. ofheating surface require two or more safety valves.Safety valves are spring loaded valves and should be regularly tested by the boiler operator on duty, unless plant policy states otherwise. Testing a safety (relief) valve is performed by simply lifting the test lever on the side of the valve. A gate valve is an isolation valve, and is used only for the purpose of stopping or allowing flow. Gate valves are used as steam stop valves, blowdown valves, etc. Gate valves should always be fully open or completely closed, never inbetween.An Outside Stem and Yoke or OS&Y valve is a gate valve designed for boiler room service. The stem and yoke are outside the valve body. A rising stem valve allows the boiler operator to know the position of the valve by looking at the stem. If the stem is extended (up or out) the valve is open. In an open position, the valve provides no resistance to the flow of steam. If the stem is down or in, the valve is closed. These valves are typically seen in steam lines.A globe valve is a modulation valve, not an isolation valve. A globe valve disrupts the flow of the fluid, even in the fully open position.A check valve allows flow in one direction only. These are often seen in feedwater lines between the pumps and the boiler.When opening any manual valve, the boiler operator should open the valve slowly in order to prevent water hammer.

Low Water Fuel Cut-Out (LWCO)

The LWCO is designed to protect the boiler from a low-water condition. The control opens the burner circuit, stopping the burner if it senses a low-water level. An LWCO that controls only the burner circuit (such as the secondary LWCO on a steam boiler) is called a single element control.Controls may also operate the feedwater pump or valve or a make-up water valve as well as the burner. They are called dual or triple element controls.If the LWCO is mechanical (a float), it must be blown down (drained) on a regular basis to prevent sediment from accumulating in the float chamber. If it is electronic, this procedure is not necessary. Both types should be disassembled and cleaned at least once per year.Testing the LWCO is done by draining the float chamber to see if the burner stops, called a controlled blowdown test.This test should be performed on a regular basis. The electronic control is tested by the evaporation or slow drain method. This test requires the feedwater supply to be secured, and the burner is allowed to operate normally. If the control is functioning properly the burner will shut off when the water level goes below the NOWL. As the water supply has been shut off to the boiler, this test is extremely dangerous and should only be done by qualified operators.

Boiler Water Treatment

There are three phases of water treatment in a boiler system:• Blowdown, which maintains the TDS (total dissolved solids) in the system• External Treatment, which removes hard salts, minerals and oxygen before the water enters the boiler.• Internal Treatment, which maintains proper water chemistry by adding chemical additives to the boiler water. The primary goal of boiler water treatment is to control solids that cause deposits in the boiler and control gases that cause corrosion. The boiler feedwater system includes the necessary equipment to supply the boiler with the heated / treated water at the NOWL for maximum boiler efficiency. A feedwater pump pumps the water from the feedwater system to the boiler.

Hardness & Scale

City and well water supply contains minerals and solids. Calcium and magnesium are the most common of the minerals found in water supplies. Water may also contain silica, iron, and other trace minerals that vary by geographic location. Hardness of water is the measurement of mineral content or scale forming salts in water. Hard water is water than contains more than 25 ppm of scale-forming minerals. Soft Water is water with low mineral content.Conductivity is a measurement of how many solids are in the water, based on the conductance (ability to conduct electricity) of the water. The more solids, the better the water conducts

electricity and the more scale will build up. Water treatment programs use conductivity as a way to measure and control the solids level in the boiler water. The watertreatment program should specify the maximum amount of conductivity allowed in the boiler water. Conductivity is controlled by blowdown.Water can be softened by the use of a water softener (sodium zeolite) that removes hardness minerals before the water enters the boiler, or softened chemically while the water is in the boiler. Most boiler plants in hard water locations use bothmethods to ensure hardness removal.Phosphates (tri-sodium phosphate, dipotassium phosphate), chelants, and polymers are used for steam boiler scale and corrosion inhibitors. Sodium nitrite and sodium molybdate are used as inhibitors in hot water systems.In addition, boiler water treatment compounds usually contain tannins and lignins for settling and dispersal of sedimentin order to prevent the sludge from adhering to the boiler surfaces.

pH

pH, the potential of Hydrogen ions, is a measurement of the acidity or basicity of the water. The pH scale runs from 0 –14, with the low end being acid and the high end being base. Untreated ground or surface water is usually in the pH range of 6 – 8. Ideal water pH for boilers will range from 8 pH to 12.7 pH, depending on the type of boiler, so the pH level of the water sometimes needs to be increased. Sodium hydroxide (caustic soda) and sodium carbonate are often used to raise the pH of the boiler water in steam systems, while sodium borate is commonly used in hot water boilers.

Gases

Steel boilers are prone to attack from the oxygen in the boiler water, which causes pitting, a severe form of corrosion.Pitting damage is irreversible. As the water is heated, gases (oxygen and carbon dioxide) are driven out of the water and settles on the metal surface, causing a corrosion cell.Water treatment programs minimize the damage caused by water as it contacts the boiler metal. Oxygen can be removed mechanically using a deaerator, and chemically (scavenged) with such compounds a sodium sulfite, bisulfite, . High pressure boiler plants typically utilize a deaerator followed by addition of chemicals to the boiler water, while low-pressure plants generally use only the chemical method of oxygen scavenging.Volatile amines, of either the filming or neutralizing type, are used for prevent of pitting and corrosion in steam and condensate return lines. Common examples are cyclohexylamine, morpholine, and DEAE.Carryover

Carryover is the term used to describe water being carried with the steam into the steam system. Carryover can lead to water hammer and wet steam.

Water hammer occurs when water is being pushed through the steam lines by the steam. This can result in damage to the system piping, valves, and fittings. Wet steam is water droplets being contained within the steam. Wet steam may notcause problems in low pressure systems, but can cause serious damage to high pressure turbines.

Maintenance of Steam Traps Considering that many Federal sites have hundreds if not thousands of traps, and that

one malfunctioning steam trap can cost thousands of dollars in wasted steam per year, steam trap maintenance should receive a constant and dedicated effort.

Excluding design problems, two of the most common causes of trap failure are oversizing and dirt.

Oversizing causes traps to work too hard. In some cases, this can result in blowing of live steam. As an example, an inverted bucket trap can lose its prime due to an abrupt change in pressure. This will cause the bucket to sink, forcing the valve open.

Dirt is always being created in a steam system. Excessive build-up can cause plugging or prevent a valve from closing. Dirt is generally produced from pipe scale or from over-treating of chemicals in a boiler.

Characteristics of Steam Trap Failure

Mechanical Steam Trap (Inverted Bucket Steam Trap)

Inverted bucket traps have a “bucket” that rises or falls as steam and/ or condensate enters the trap body. When steam is in the body, the bucket rises closing a valve. As condensate enters, the bucket sinks down, opening a valve and allowing the condensate to drain. Inverted bucket traps are ideally suited for water-hammer conditions but may be subject to freezing in low temperature climates if not insulated. Usually, when this trap fails, it fails open. Either the bucket loses its prime and sinks or impurities in the system may prevent the valve from closing.

Thermostatic Steam Trap (Bimetallic and Bellows Steam Traps)

Thermostatic traps have, as the main operating element, a metallic corrugated bellows that is filled with an alcohol mixture that has a boiling point lower than that of water. The bellows will contract when in contact with condensate and expand when steam is present. Should a heavy condensate load occur, such as in start-up, the bellows will remain in a contracted state, allowing condensate to flow continuously. As steam builds up, the bellows will close. Therefore, there will be moments when this trap will act as a “continuous flow” type while at other times, it will act intermittently as it opens and closes to condensate and steam, or it may remain totally closed. These traps adjust automatically to variations of steam pressure but may be damaged in the presence of water hammer. They can fail open should the bellows become damaged or due to

particulates in the valve hole, preventing adequate closing. There can be times when the tray becomes plugged and will fail closed.

Checklist Indicating Possible Steam Trap Failure

• Abnormally warm boiler room. • Condensate received venting steam. • Condensate pump water seal failing prematurely. • Overheating or underheating in conditioned space. • Boiler operating pressure difficult to maintain. • Vacuum in return lines difficult to maintain. • Water hammer in steam lines. • Steam in condensate return lines. • Higher than normal energy bill. • Inlet and outlet lines to trap nearly the same temperature.

Maintenance of Chillers

Similar to boilers, effective maintenance of chillers requires two activities: first, bring the chiller to peak efficiency and second, maintain that peak efficiency. There are some basic steps facility professionals can take to make sure their building’s chillers are being maintained properly. Among them are:

Inspecting the chiller as recommended by the chiller manufacturer. Typically, this should be done at least quarterly.

Routine inspection for refrigerant leaks.

Checking compressor operating pressures.

Checking all oil levels and pressures.

Examining all motor voltages and amps.

Improved maintenance

As already stated, with the majority of the lifecycle costs set during the design phase of theplant, as the reliability and maintainability depend on the plant design, the maintenance costs once the plant is in operation are important for the power producers as they are the only source of costs the owner of the plant can truly affect. This cost optimization can be done by selecting equipment that has high maintainability i.e. can be maintained easily and cost effectively.The maintenance method selection should be adaptive so that the experiencesgained during operation are evaluated and the method selections are reassessed andquestioned at regular intervals. This process should be continuous, particularly when the plant is ageing and the wearing of the equipment parts starts to appear.

Maintenance of Steam Traps

Considering that many Federal sites have hundreds if not thousands of traps, and that one malfunctioning steam trap can cost thousands of dollars in wasted steam per year, steam trap maintenance should receive a constant and dedicated effort.

Excluding design problems, two of the most common causes of trap failure are oversizing and dirt.

Oversizing causes traps to work too hard. In some cases, this can result in blowing of live steam. As an example, an inverted bucket trap can lose its prime due to an abrupt change in pressure. This will cause the bucket to sink, forcing the valve open.

Dirt is always being created in a steam system. Excessive build-up can cause plugging or prevent a valve from closing. Dirt is generally produced from pipe scale or from over-treating of chemicals in a boiler.Financial reasons

There is considerable evidence, borne out by companies’ practical experiences, thateffective safety and health management in the workplace contributes to businesssuccess. Accidents and ill-health inflict significant costs, often hidden andunderestimated.

Legal reasons

Carrying out a risk assessment, preparing a safety statement and implementing whatyou have written down are not only central to any safety and health managementsystem, they are required by law.Health and Safety Authority inspectors visiting workplaces will want to know howemployers are managing safety and health. If they investigate an accident, they willscrutinise the risk assessment and safety statement, and the procedures and workpractices in use. Make sure that these stand up to examination.

Moral and ethical reasons

The process of carrying out a risk assessment, preparing a safety statement andimplementing what you have written down will help employers prevent injuries and illhealthat work. Employers are ethically bound to do all they can to ensure that youremployees do not suffer illness, a serious accident or death.

11. Maintaining Boiler Safety Safety

Regard for personnel safety is an item that is first and foremost in the design, construction, operation, and maintenance of industrial manufacturing facilities. Sometimes serious and fatal injuries are caused by catastrophic equipment failure that stems from years of seemingly innocent neglect or poor operation and maintenance.

When it comes to potential catastrophic failure caused by poor operating and maintenance practices, there is probably no more potentially dangerous equipment operating in an industrial manufacturing facility than steam and power generating equipment. The boiler is often the largest, most expensive, and potentially most dangerous piece of equipment, if not operated and maintained properly.

Even the most sophisticated high-temperature and pressure watertube boiler can be simply described as pressure parts (drums, headers, and steel tubes) which contain high-

pressure steam and water. The tube surface transfers heat to the water from a fuel being combusted in a controlled manner outside of the tube surface. A firetube boiler is simply the opposite with the fuel combustion on the inside of the tube surface.

Boiler failures

Catastrophic boiler failures can threaten the safety of operating personnel. Fuel explosions, low water, or poor feedwater quality generally causes them.

Fuel explosions

One of the most dangerous situations in the operation of a boiler is that of a fuel explosion in the furnace. The inherent cause of fuel explosions can generally be traced back to an operations or maintenance problem. If a steam boiler is properly operated and maintained, including performance of all the necessary routine preventive maintenance, the likelihood of a fuel explosion is virtually eliminated.

Low-water incidence

The potential for severe and even catastrophic damage to a boiler as a result of low-water conditions is easy to imagine, considering that furnace temperatures exceed 1800 F, yet the physical properties of carbon steel change dramatically at temperatures above 850 F.

The only reason a boiler can withstand these furnace temperatures is the presence of water in all tubes of the furnace at all times when a fire is present. In a very short period of time, continued firing during a low water condition literally melts steel boiler tubes.

Typical industrial boilers are natural circulation and do not utilize pumps to move water through the tubes. Instead, these units rely on the differential density between steam and water to provide the necessary water circulation. The water level is critical to ensure a flooded supply of water to downcomer tubes.

Because sufficient water level is critical, modern boilers are equipped with automatic low-water trip switches. Some older boilers may not have these relatively inexpensive devices.

If a boiler does not have low-water trips, have these devices installed. Low-watertrips protect boiler pressure parts by shutting down the fuel combustion process, eliminating high temperatures in the furnace when the natural circulation cooling process is interrupted.

Control of the boiler drum level is sophisticated, and even the best-tuned control systems cannot always prevent a low-water condition. The water level in a steam drum is actually a fairly

unstable compressible mixture of water and steam bubbles that shrink and swell with pressure changes, firing rate changes, and when colder feedwater is added.

All properly designed installations - both gas/oil and solid fuel units -- should be installed with redundant and dissimilar low-water trips, conductive and float-actuated types. Unfortunately, an alarming number of boilers equipped with low-water trips are destroyed each year.

There are several common reasons for low-water trip failures.

Disabled trip circuits. A typical scenario involves bypassing the switches to eliminate nuisance trips due to improperly tuned controls, safety device failure, etc. This approach is a Band-Aid to cover the real problem and should never be allowed.

Inoperative trip switches. Trip switches should be blown down regularly to exercise the trip devices and remove potential sludge buildup. A properly designed installation allows the trip devices to be blown down each shift without the boiler tripping offline. This blowdown keeps them clean and verifies proper operation of the low-water protection and alarm circuitry.

Poor feedwater quality

Feedwater is treated to protect the boiler from two basic problems: buildup of solid deposits on the waterside of the tubes and corrosion.

Water that enters the boiler is vaporized to steam, leaving solids behind in the form of scale or buildup in the areas of highest heat transfer rate.

A buildup of scale deposits inside boiler tubes produces an insulating layer which inhibits the ability of the water to remove heat from the tube surface. If this condition becomes severe enough and allowed to continue, the result is localized overheating of the tube and eventual failure.

Whether caused by low water or poor boiler water quality, potentially dangerous steam explosions canoccur when overheated pressure parts suddenly fail under high pressure. A steam explosion in a boiler house can, in seconds, produce ambient conditions of intolerable heat and reduced oxygen levels below survivable limits.

To prevent deposits on tubes, the level of solids in the boiler feedwater must be maintained at acceptable limits. The higher the operating pressure and temperature of the boiler, the more stringent the requirements for proper feedwater treatment.

Unless a power generation turbine is involved, or the raw water quality Is particularly bad, most industrial boilers operate at sufficiently low pressures to enable the use of simple sodium zeolite water softeners for feedwater treatment.

At higher pressures and when turbines and superheaters are involved, more complex feedwater treatment systerns, such as reverse osmosis and demineralizer systems, are required.

Waterside tube corrosion is generally caused by the existence of contaminants in the boiler feedwater, which is a combination of makeup water and condensate returns.

Feedwater contaminants include oxygen, excessive water treatment chemicals, oils, miscellaneous metals and chemical compounds, and resin.

Dissolved oxygen is a common and constant threat to boiler tube integrity. The use of modem, sophisticated cbelant water treatment programs has dramatically improved the cleanliness of boiler heat transfer surfaces to such an extent that essentially bare-metal conditions exist.

Since only a thin magnetic oxide film remains on boiler metal surfaces, oxygen control is extremely important. The typical boiler facility is equipped with a deaerating feedwater heater to remove the majority of oxygen. In boilers operating below 1000 psig, the oxygen scavenger - sodium sulfite - is continuously fed to the storage tank of the deaerator to ensure the absence of free oxygen.

One of the most serious types of oxygen corrosion is oxygen pitting, which is concentrated on a very small area. Pressure part failures can occur, even though a relatively small amount of corrosion and loss of metal has been experienced.

A chelant boiler water treatment program that is not properly maintained to ensure proper dosages of chelating chemicals can create problems with consequences these chemicals are injected to prevent Chelant corrosion or attack develops only when excess concentrations of sodium salt are maintained substantially above the control level for an extended period of time. The resultant attack is a dissolving or thinning of metal, unlike oxygen pitting. The attack concentrates on areas of stress within the boiler, such as: rolled tube ends, baffle edges, tube welds, threaded members, and other nonstress relieved areas.

The inadvertent introduction of acid and caustic can cause the most devastating immediate damage to a boiler. The presence of either of these chemicals can cause many different types of corrosion and destruction ofimetal integrity. These chemicals are commonly introduced into a boiler for several reasons.

Equipment failure or malfunction. A typical problem might be leaking regenerant isolation valves or failure of an automatic controller, resulting in an inadequate rinse cycle. - Poor water treatment system design. Double block and bleed valve systems should be used wherever any regenerant chemicals are introduced into the water system to protect against damage due to valve failure.

Poor water treatment system training and operation. If operators are not properly trained and cognizant of the importance of operating these often-sophisticated systems, they might be responsible for pumping concentrated acid and caustic into the boiler. A less likely problem might be improperly carrying out the regeneration of water treatment equipment, such as improper rinsing of residual acid and caustic.

Undetected contain I nation of condensate returns is another common problem, which leads to boiler feedwater contamination. Contaminants can vary from metals such as copper and iron, to oils and process chemicals.

Heavy metal contamination is usually a function of the materials of construction of the process equipment and the condensate system.

Oils and process chemicals are generally introduced into the condensate system due to process equipment failures or corrosion-caused leaks in equipment, such as heat exchangers, pump and gland seals, etc.

The biggest risk associated with condensate system contamination is a catastrophic failure of a piece of process equipment, which results in the introduction of significant quantities of undesirable chemicals or compounds into the boiler. For this reason, prudent boiler operations should include continuous monitoring of the quality of condensate being returned from the process with automatic dump capability in case of contamination.

Another problem that sometimes causes severe boiler fouling is the introduction of ion exchange resin into the boiler feedwater system. This situation is frequently caused by the failure of the ion exchange vessel internal piping or lateral screens.

Depending upon the operating pressure of the boiler and type of resin, this problem can result in a severe coating of resin material on boiler surfaces. An inexpensive and very worthwhile method to alleviate the chance of this type of contamination is to install a resin trap on the outlet of any ion exchange vessel. Resin traps not only protect the boiler from contamination, but also prevent the loss of very expensive resin.

Boiler feedwater contamination and resultant corrosion can be a slow, degenerative process, or 'an instantaneous, catastrophic event. Routine and efficient maintenance procedures greatly mitigate the chances of both types of occurrences. Consistent boiler water and feedwater quality monitoring and testing provides operating personnel not only with historical data, but also with a timely warning anytime feedwater quality changes dramatically.

Improper blowdown

When boiler feedwater is high quality, it is maintained by following proper blowdown practices. The concentration of undesirable solids in boiler water is reduced through the proper operation of a continuous purge or blowdown system and by performing intermittent bottom blowdowns on a regular basis.

The sodium zeolite water softening process is an ion exchange operation that exchanges harmful scale-producing calcium and magnesium ions for sodium ions.

The main purpose of blowdown is to maintain the solids concentration of the boiler water within certain acceptable limits. The blowdown rate can be determined by any one of several factors, which include total dissolved solids, suspended solids, silica, and alkalinity .

The continuous blowdown rate is set to control the boiler water within ABMA-recommended acceptable limits. A well-designed continuous blowdown system constantly monitors boiler water conductivity (solids concentrations) and adjusts the blowdown rate to maintain the control range.

If the boiler water exceeds the recommended limits, potential problems can occur, including scale and sludge formation, corrosion, and moisture carryover due to foaming, and poor steam drum separation equipment performance. This foaming phenomenon associated with high conductivity can also cause drum level instability leading to nuisance water level alarms and potential boiler trips.

Sometimes, it is necessary to perform intermittent bottom blowdowns to dramatically reduce solids concentrations in the boiler water. Also, intermittent bottom blowdowns of water wall headers and the mud drum are critical to remove potential sludge buildup to keep all water circuitry clear. Generally, the only bottom blowdown that can be performed while the unit is being fired is from the mud drum.

Blowdown of lower water wall headers, particularly the furnace wall headers, should not be performed while the unit is being fired.This action could potentially result In water wall tube overheat damage due to the interruption of the boiler natural circulation.

Drum operating pressure - PSIG

Total dissolved solids - PPM

Total alkalinity - PPM

Silica - PPM

Total suspended solids - PPM

0300 3500 700 150 15

301450 3000 600 90 10

451600 2500 500 40 8

601750 1000 200 30 3

751900 750 150 20 2

9011000 625 125 8 1

ABMA maximum recommended concentration in water of an operation boiler

Lower water wall headers should be routinely blown down every time the unit is brought out of service after fuel fining has been halted and the unit is still under pressure. Care should be taken to perform a blowdown of a limited duration to maintain visibility of the boiler water level in the sight glass. Additional bottom blows can be performed once feed water is added to raise the level back up in the sight glass.

The single biggest problem caused by poor blowdown practices is the failure to periodically blow down the boiler water columns to ensure that the low-watertrip devices are kept operational.

Steam boiler failures There are two common reasons for boiler failure:

Short-term operator or maintenance errors that have a dramatic, immediate effect toward causing a catastrophic failure or incident

Long-term operating or maintenance practices that, over time, cause or allow a condition to develop that results in a catastrophic failure or incident

Common causes of fuel explosions

Fuel-rich mixtures can occur any time that insufficient air is supplied for the amount of fuel being burned. Never add air to a dark, smoky furnace. First, trip the unit to remove the ignition source, purge thoroughly, and then correct the problem. A lean mixture, which results in more air than necessary, while not efficient, is not dangerous.

Poor atomization of oil can cause an accumulation in the furnace and create a localized volatile mix lure of unburned fuel, which can result in an explosion. To prevent this situation, the oil gun sprayer assembly must be free of debris and the atomizing steam or air and fuel oil pressures must be properly adjusted.

Improper purge can leave a combustible mixture in a boiler.Many explosions occur during attempts to relight a burner after it has tripped because of another problem. The pilot then ignites the large inventory of unburned combustible gases in the furnace, which produces the explosion.

This scenario can be avoided by investigating the cause of the trip and allowing the furnace to purge thoroughly before any attempt to relight

Common causes of low water conditions

Feedwater pump failure Control valve failure Loss of water to the deaerator or makeup water system Drum level controller failure Drum level controller inadvertently left in "manual" position Loss of plant air pressure to the control valve actuator Safety valve lifting and then reseating

Large and sudden change in steam load and/or firing rate

Boiler safety operation and maintenance practices

Frequently observe the burner flame, especially when firing oil, to identify plugged sprayer tips and other combustion problems. This approach provides an early warning.

Investigate and identify the cause of any trip before attempting to relight. Before lighting a boiler, always purge the furnace thoroughly. Perform routine maintenance, calibration, and testing of the burner management system

and combustion controls, especially safety devices and transmitters. Verify that the water treatment system is operating properly, producing boiler feedwater

ofsufficiently high quality for the operating temperatures and pressures involved. Although zero hardness is always an absolute criteria, other water quality standards based on operating pressures and temperatures as recommended by ABMA should be followed.Never use untreated water in a boiler.

Blow down all the dead legs of the low water trips, water column, etc., on a regular basis to prevent sludge buildup in these areas, which leads to device malfunction. Never, under any circumstance, disable a low-water trip.

Verify that water leaving the dearator is free of oxygen, that the deaerator is operated at the proper pressure, and that the storage tank water is at saturation temperature. A continuous vent from the deaerator is necessary to allow the discharge of non condensable gases.

Continuously monitor the quality of condensate coming back from the process to enable the diversion of condensate in the event of a catastrophic process equipment failure.

Adjust continuous blowdown to maintain conductivity of the boiler water within required operating limits and operate the mud drum blowdown on a regular basis. Never blow down a furnace wall header while the boiler is operating.

The boiler waterside should be inspected on a regular basis. If there are any signs of scaling or buildup of solids on the tubes, water treatment adjustments should be made. The boiler might require either a mechanical or chemical cleaning.

The deaerator vessel and internals should be inspected on a regular basis for signs of corrosion. This check is an important safety issue because a deacrator can rupture from oxygen corrosion damage. The catastrophic failure of an operating deacrator is the most common source of a fatal steam explosion inside a boiler house

This documentation does not replace the Owners existing company safety operating procedures and instructions. All normal safety precautions should be followed when operating boilers, burners, and fuel systems. Consult the Owners plant operating and safety authorities for complete details. In addition to the categorized hazards shown in the various sections of this manual, there are general type categories, which need emphasis:

Manufacturer's Instructions - Equipment manufacturer's instructions should be followed. Training - Employees must be trained in safety prior to operation of the equipment. The

training in safety should be a continuous process for the purpose of educating employees

to recognize and to keep safety in their minds throughout their careers. A training program should be established and maintained.

Housekeeping - Good housekeeping is essential for safety and good plant operation. Poor housekeeping results in increased safety hazards. A clean and orderly environment will foster safety.

Clothing and Protective Equipment - Proper clothing should be worn at all times. Avoid loose clothing and jewelry. Protective equipment must be worn when necessary (i.e.: hard hats, respirators, ear plugs, goggles, gloves, safety shoes, etc.). Never operate rotating equipment, mechanically automated devices, or electrically and pneumatically operated control components unless guides, shields, or covers are in place.

Hot Surfaces - Many hot surfaces exist in a boiler area and even non-heated surfaces can become uncomfortably warm, therefore, employees, especially new employees, must be made aware of these conditions. Refractory and insulation are typically provided to encounter elevated surface temperatures in some installations. Care must be exercised to prevent burns and other thermal hazards when near the boiler. Never enter the boiler until an adequate cool-off period has been observed and the Owner's entry procedures have been completed.

Lockout and Tagout Procedures - Every plant should have a formalized lockout and tagout procedure that is strictly enforced.

Remote Starting of Equipment - Much of the equipment in plants are started remotely and/or automatically without warning; therefore, employees must be alert to avoiding that equipment which can be started remotely. If work is to be done on any equipment, lockout and tagout procedures must be followed. Attach signs to equipment such as " AT DO NOT START - MEN WORK". Attach a similar sign on the equipment control panel.

Unexpected Noise - A sudden and/or unexpected noise may cause employees to move involuntary. Such reaction may result in injury. Precautions against this are hard to take out but experience probably is the best teacher to prevent such inadvertent responses.

Unconventional Fuels - Sometimes unconventional fuels need to be burned in boilers. When this is done, particular attention should be paid to the hazards that can result. Theses may from characteristics in the fuels, toxic chemicals in the fuel, and toxic chemicals produced through combustion. Persons knowledgeable in the use of such unconventional fuels should be consulted concerning the problems that may be encountered. Because of the wide variety and limited use, such fuels are not addressed in this manual.

Fire and Explosion Hazards - A fired boiler utilizes fuels which are flammable and potentially explosive. Extreme care should be exercised when making fuel-piping connections. Use the correct gasket, bolts, thread lubricants, and tightening torque to prevent leaks. It is recommended that drain valve and/or vent piping be channeled to safe locations.

12. CONCLUSION

The above report is for improvement in efficiency of the boiler and to solve the boiler safety and maintenance problems. we can conclude that efficiency of boiler can be increased by reducing loss due to unburnt fue ,reducing dry gas loss, reducing loss due to fuel moisture, reducing loss due to radition. By improving efficiency, the use of boiler in industries is increasing day by day.

For improving boiler efficiency we can use the technology like fluidized bed combustion, AFBC / bubbling bag , circulating fluidized bed combustion, pressurized fluid bed combustion.

For smooth working of boiler maintenance tips like normal operating water level, blowdown, inspections, valves and boiler water treatments can be taken into consideration.

For maintaining safety in industries causes of boiler failure like fuel explosions,low water incidence,etc can be consider the most.

13. REFERANCEWWW.GOOGLE.COM.

WWW.WIKIPEDIA.COM.

WWW.BOILER.COM.

WWW.E-BOOK.COM . POWER PLANT ENGG. S.C.ARORA S.DOMKUNDARWAL

http://WWW.WIKIPEDIA.COM/

http://WWW.GOOGLE.COM/

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