Reference Material

Workshopon

Efficient Operation of Boilers & Maintenance

16th December 2005Hotel Nisarga, Bhopal

Sponsored byDept. of Industrial Policy & PromotionMin. of Commerce & Industry, Govt. of

IndiaOrganised by

National Productivity CouncilE-5/112, Arera Colony

Bhopal – 462016Ph: 0755-5277512, Fax : 0755-2466537

Sl. No.

CONTENTS Page No.

1. INTRODUCTION 1

2. BOILER TYPES & CLASSIFICATION 3

3. PERFORMANCE EVALUATION OF BOILERS 7

4. BOILER BLOW DOWN 11

5. BOILER WATER TREATMENT 14

6. ENERGY CONSERVATION OPPORTUNITIES 19

7.CASE STUDY

24

8.CHECKLIST & TIPS FOR ENERGY EFFICIENCY

26

9.MAINTENANCE ACTIVITIES FOR BOILERS

BOILER FED WATER - THERMAX MATERIAL

BOILERS

Introduction

A boiler is 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 through a conveying medium without physical contact, (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.  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 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.

Indian Boiler Regulation

The Indian Boilers Act was enacted to consolidate and amend the law relating to steam boilers. Indian Boilers Regulation (IBR) was created in exercise of the powers conferred by section 28 & 29 of the Indian Boilers Act.

IBR Steam Boilers means any closed vessel exceeding 22.75 liters in capacity and which is used expressively for generating steam under pressure and includes any mounting or other fitting attached to such vessel, which is wholly, or partly under pressure when the steam is shut off.

IBR Steam Pipe means any pipe through which steam passes from a boiler to a prime mover or other user or both, if pressure at which steam passes through such pipes exceeds 3.5 kg/cm2 above atmospheric pressure or such pipe exceeds 254 mm in internal diameter and includes in either case any connected fitting of a steam pipe.

Typical Boiler Specification

Boiler Make & Year :XYZ & 2003MCR(Maximum Continuous Rating) :10TPH (F & A 100oC)Rated Working Pressure :10.54 kg/cm2(g)Type of Boiler : 3 Pass Fire tubeFuel Fired : Fuel Oil

Figure 1 Boiler Room Schematic

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. A typical boiler room schematic is shown in Figure.1

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.

Figure .3 Water Tube Boiler

Figure.4 Packaged Boiler

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. (Refer Figure 2). 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 (see figure 3). 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 (Refer Figure 4).

The features of package boilers are:

Figure 2 Fire Tube Boiler

Figure 5 Chain Grate Stoker

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 stoker2. 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 (see Figure .5).

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, since ignition is almost instantaneous when firing rate is increased. Hence, the spreader stoker is favored over other types of stokers in many industrial applications.

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.

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 (see Figure 6).

Figure 6 Tangential Firing

FBC Boiler

When an evenly distributed air or gas is passed upward through a finely divided bed of solid particles such as sand supported on a fine mesh, the particles are undisturbed at low velocity. As air velocity is gradually increased, a stage is reached when the individual particles are suspended in the air stream. Further, increase in velocity gives rise to bubble formation, vigorous turbulence and rapid mixing and the bed is said to be fluidized.

Figure 7 Fluidised Bed Combustion Circulating Fluidised Bed Boiler

If the sand in a fluidized state is heated to the ignition temperature of the coal and the coal is injected continuously in to the bed, the coal will burn rapidly, and the bed attains a uniform temperature due to effective mixing. Proper air distribution is vital for maintaining uniform fluidisation across the bed.). Ash is disposed by dry and wet ash disposal systems.

Fluidised bed combustion has significant advantages over conventional firing systems and offers multiple benefits namely fuel flexibility, reduced emission of noxious pollutants such as SOx and NOx, compact boiler design and higher combustion efficiency. More details about FBC boilers are given in Chapter 6 on Fluidized Bed Boiler.

Boiler Efficiency

4 Performance Evaluation of Boilers

The performance parameters of boiler, like efficiency and evaporation ratio reduces with time due to poor combustion, heat transfer surface fouling and poor operation and maintenance. Even for a new boiler, reasons such as deteriorating fuel quality, water quality etc. can result in poor boiler performance. Boiler efficiency tests help us to find out the deviation of boiler efficiency from the best efficiency and target problem area for corrective action.

Boiler Efficiency

Thermal efficiency of boiler is defined as the percentage of heat input that is effectively utilised to generate steam. There are two methods of assessing boiler efficiency.

1) The Direct Method: Where the energy gain of the working fluid (water and steam) is compared with the energy content of the boiler fuel.

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

a. Direct Method

This is also known as ‘input-output method’ due to the fact that it needs only the useful output (steam) and the heat input (i.e. fuel) for evaluating the efficiency. This efficiency can be evaluated using the formula

Parameters to be monitored for the calculation of boiler efficiency by direct method are :

Quantity of steam generated per hour (Q) in kg/hr. Quantity of fuel used per hour (q) in kg/hr. The working pressure (in kg/cm2(g)) and superheat temperature (oC), if any The temperature of feed water (oC) Type of fuel and gross calorific value of the fuel (GCV) in kcal/kg of fuel

Boiler Efficiency Evaluation

Direct Method Indirect Method

Heat Output Heat Input

=

Boiler efficiency () = :

Where, hg – Enthalpy of saturated steam in kcal/kg of steam hf - Enthalpy of feed water in kcal/kg of water

Example

Find out the efficiency of the boiler by direct method with the data given below:

– Type of boiler : Coal fired – Quantity of steam (dry) generated : 8 TPH– Steam pressure (gauge) / temp : 10 kg/cm2(g)/ 180 0C– Quantity of coal consumed : 1.8 TPH– Feed water temperature : 850 C– GCV of coal : 3200 kcal/kg– Enthalpy of steam at 10 kg/cm2 pressure : 665 kcal/kg (saturated)– Enthalpy of feed water : 85 kcal/kg

Boiler efficiency () = :

= 80 %

It should be noted that boiler may not generate 100% saturated dry steam, and there may be some amount of wetness in the steam.

Advantages of direct method:

Plant people can evaluate quickly the efficiency of boilers

Requires few parameters for computation

Needs few instruments for monitoring

Disadvantages of direct method:

Does not give clues to the operator as to why efficiency of system is lower

Does not calculate various losses accountable for various efficiency levels

Q x (hg – hf) q x GCV

x 100

8 x (665 – 85)1.8 x 3200

x 100

b. Indirect Method

There are reference standards for Boiler Testing at Site using indirect method namely British Standard, BS 845: 1987 and USA Standard is ‘ASME PTC-4-1 Power Test Code Steam Generating Units’.

Indirect method is also called as heat loss method. The efficiency can be arrived at, by subtracting the heat loss fractions from 100. The standards do not include blow down loss in the efficiency determination process. A detailed procedure for calculating boiler efficiency by indirect method is given below. However, it may be noted that the practicing energy mangers in industries prefer simpler calculation procedures. The principle losses that occur in a boiler are:

Loss of heat due to dry fluegas

Loss of heat due to moisture in fuel and combustion air

Loss of heat due to combustion of hydrogen

Loss of heat due to radiation

Loss of heat due to unburnt

In the above, loss due to moisture in fuel and the loss due to combustion of hydrogen are dependent on the fuel, and cannot be controlled by design.

The data required for calculation of boiler efficiency using indirect method are:

Ultimate analysis of fuel (H2, O2, S, C, moisture content, ash content) Percentage of Oxygen or CO2 in the flue gas Flue gas temperature in 0C (Tf) Ambient temperature in 0C (Ta) & humidity of air in kg/kg of dry air. GCV of fuel in kcal/kg Percentage combustible in ash (in case of solid fuels) GCV of ash in kcal/kg (in case of solid fuels)

Solution :

Theoretical air requirement =[(11.43 x C) + [{34.5 x (H2 – O2/8)} + (4.32 x S)]/100 kg/kg of fuel

Excess Air supplied (EA) =

Actual mass of air supplied/ kg of fuel (AAS) = {1 + EA/100} x theoretical air

m x Cp x (Tf – Ta ) x 100

O2% x 100 (21 – O2%)

i Percentage heat loss due to dry flue gas = GCV of fuelm = mass of dry flue gas in kg/kg of fuel

m = (mass of dry products of combustion / kg of fuel) + (mass of N2 in fuel on 1 kg basis ) + (mass of N2 in actual mass of air we are supplying).

Cp = Specific heat of flue gas (0.23 kcal/kg )

ii. Percentage heat loss due to evaporation of water formed due to H2 in fuel

=

Where, H2 – percentage of H2 in 1 kg of fuel Cp – Specific heat of superheated steam (0.45 kcal/kg)

iii. Percentage heat loss due to evaporation of moisture present in fuel

=

Where, M – % moisture in 1kg of fuel Cp – Specific heat of superheated steam (0.45 kcal/kg)

iv. Percentage heat loss due to moisture present in air

=

Cp – Specific heat of superheated steam (0.45 kcal/kg)

v. Percentage heat loss due to unburnt in fly ash

== =

vi Percentage heat loss due to unburnt in bottom ash

Total ash collected per kg of fuel burnt x G.C.V of bottom ash x 100 =

GCV of fuel

vii Percentage heat loss due to radiation and other unaccounted loss

9 x H2 {584 + Cp (Tf – Ta)} x 100GCV of fuel

M {584 + Cp (Tf – Ta)} x 100 GCV of fuel

AAS x humidity factor x Cp x (Tf – Ta) x 100GCV of fuel

Total ash collected / Kg of fuel burnt x G.C.V of fly ash x 100= GCV of fuel

The actual radiation and convection losses are difficult to assess because of particular emissivity of various surfaces, its inclination, air flow pattern etc. In a relatively small boiler, with a capacity of 10 MW, the radiation and unaccounted losses could amount to between 1% and 2% of the gross calorific value of the fuel, while in a 500 MW boiler, values between 0.2% to 1% are typical. The loss may be assumed appropriately depending on the surface condition.

Boiler Evaporation RatioEvaporation ratio means kilogram of steam generated per kilogram of fuel consumed.Typical Examples: Coal fired boiler : 6

Oil fired boiler : 13i.e 1 kg of coal can generate 6 kg of steam

1 kg of oil can generate 13 kg of steamHowever, this figure will depend upon type of boiler, calorific value of the fuel and associated efficiencies.

5 Boiler Blowdown

When water is boiled and steam is generated, any dissolved solids contained in the water remain in the boiler. If more solids are put in with the feed water, they will concentrate and may eventually reach a level where their solubility in the water is exceeded and they deposit from the solution. Above a certain level of concentration, these solids encourage foaming and cause carryover of water into the steam. The deposits also lead to scale formation inside the boiler, resulting in localized overheating and finally causing boiler tube failure.

It is, therefore, necessary to control the level of concentration of the solids and this is achieved by the process of 'blowing down', where a certain volume of water is blown off and is automatically replaced by feed water - thus maintaining the optimum level of total dissolved solids (TDS) in the boiler water. Blow down is necessary to protect the surfaces of the heat exchanger in the boiler. However, blow down can be a significant source of heat loss, if improperly carried out. The maximum amount of total dissolved solids (TDS) concentration permissible in various types of boilers is given in Table.1.

Efficiency of boiler () = 100 – (i + ii + iii + iv + v + vi + vii)

Table .1 Recommended TDS Levels for Various Boilers

Boiler Type Maximum TDS (ppm)*

1. Lancashire 10,000 ppm

2. Smoke and water tube boilers (12 kg/cm2) 5,000 ppm

3. Low pressure Water tube boiler 2000-3000

3. High Pressure Water tube boiler with superheater etc. 3,000 - 3,500 ppm

4. Package and economic boilers 3,000 ppm

5. Coil boilers and steam generators 2000 (in the feed water

Note: Refer guidelines specified by manufacturer for more details *parts per million

Conductivity as Indicator of Boiler Water Quality

Since it is tedious and time consuming to measure total dissolved solids (TDS) in boiler water system, conductivity measurement is used for monitoring the overall TDS present in the boiler. A rise in conductivity indicates a rise in the "contamination" of the boiler water.

Conventional methods for blowing down the boiler depend on two kinds of blowdown - intermittent and continuous

Intermittent Blowdown

The intermittent blown down is given by manually operating a valve fitted to discharge pipe at the lowest point of boiler shell to reduce parameters (TDS or conductivity, pH, Silica and Phosphates concentration) within prescribed limits so that steam quality is not likely to be affected. In intermittent blowdown, a large diameter line is opened for a short period of time, the time being based on a thumb rule such as “once a shift for 2 minutes”.

Intermittent blowdown requires large short-term increases in the amount of feed water put into the boiler, and hence may necessitate larger feed water pumps than if continuous blow down is used. Also, TDS level will be varying, thereby causing fluctuations of the water level in the boiler due to changes in steam bubble size and distribution which accompany changes in concentration of solids. Also substantial amount of heat energy is lost with intermittent blowdown.

Continuous Blowdown

There is a steady and constant dispatch of small stream of concentrated boiler water, and replacement by steady and constant inflow of feed water. This ensures constant TDS and steam purity at given steam load. Once blow down valve is set for a given conditions, there is no need for regular operator intervention.

Even though large quantities of heat are wasted, opportunity exits for recovering this heat by blowing into a flash tank and generating flash steam. This flash steam can be used for pre-heating boiler feed water or for any other purpose (see Figure 2.8 for blow down heat recovery system). This type of blow down is common in high-pressure boilers.

Blowdown calculations

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

Blow down (%) = Feed water TDS x % Make up water Maximum Permissible TDS in Boiler water

If maximum permissible limit of TDS as in a package boiler is 3000 ppm, percentage make up water is 10% and TDS in feed water is 300 ppm, then the percentage blow down is given as:

300 x 10 =

Figure 8

3000

= 1 %

If boiler evaporation rate is 3000 kg/hr then required blow down rate is:

3000 x 1 =

100

= 30 kg/hr

Benefits of Blowdown

Good boiler blow down control can significantly reduce treatment and operational costs that include:

Lower pretreatment costs Less make-up water consumption Reduced maintenance downtime Increased boiler life Lower consumption of treatment chemicals

6 Boiler Water Treatment Producing quality steam on demand depends on properly managed water treatment to control steam purity, deposits and corrosion.  A boiler is the sump of the boiler system.  It ultimately receives all of the pre-boiler contaminants. Boiler performance, efficiency, and service life are direct products of selecting and controlling feed water used in the boiler.

When feed water enters the boiler, the elevated temperatures and pressures cause the components of water to behave differently.  Most of the components in the feed water are soluble. However, under heat and pressure most of the soluble components come out of solution as particulate solids, sometimes in crystallized forms and other times as amorphous particles.  When solubility of a specific component in water is exceeded, scale or deposits develop. The boiler water must be sufficiently free of deposit forming solids to allow rapid and efficient heat transfer and it must not be corrosive to the boiler metal. 

Deposit Control

Deposits in boilers may result from hardness contamination of feed water and corrosion products from the condensate and feed water system. Hardness contamination of the feed water may arise due to deficient softener system.

Deposits and corrosion result in efficiency losses and may result in boiler tube failures and inability to produce steam. Deposits act as insulators and slow heat transfer. Large amounts of deposits throughout the boiler could reduce the heat transfer enough to reduce

the boiler efficiency significantly. Different type of deposits affects the boiler efficiency differently. Thus it may be useful to analyse the deposits for its characteristics. The insulating effect of deposits causes the boiler metal temperature to rise and may lead to tube-failure by overheating.   Impurities causing deposits 

The most important chemicals contained in water that influences the formation of deposits in the boilers are the salts of calcium and magnesium, which are known as hardness salts.

Calcium and magnesium bicarbonate dissolve in water to form an alkaline solution and these salts are known as alkaline hardness. They decompose upon heating, releasing carbon dioxide and forming a soft sludge, which settles out. These are called temporary hardness-hardness that can be removed by boiling.

Calcium and magnesium sulphates, chlorides and nitrates, etc. when dissolved in water are chemically neutral and are known as non-alkaline hardness. These are called permanent hardness and form hard scales on boiler surfaces, which are difficult to remove. Non-alkalinity hardness chemicals fall out the solution due to reduction in solubility as the temperature rises, by concentration due to evaporation which takes place within the boiler, or by chemical change to a less soluble compound.

Silica

The presence of silica in boiler water can rise to formation of hard silicate scales. It can also associate with calcium and magnesium salts, forming calcium and magnesium silicates of very low thermal conductivity. Silica can give rise to deposits on steam turbine blades, after been carried over either in droplets of water in steam, or in volatile form in steam at higher pressures.

Two major types of boiler water treatment are: Internal water treatment and External water treatment.

Internal Water Treatment

Internal treatment is carried out by adding chemicals to boiler to prevent the formation of scale by converting the scale-forming compounds to free-flowing sludges, which can be removed by blowdown. This method is limited to boilers, where feed water is low in hardness salts, to low pressures- high TDS content in boiler water is tolerated, and when only small quantity of water is required to be treated. If these conditions are not applied, then high rates of blowdown are required to dispose off the sludge. They become uneconomical from heat and water loss consideration.

Different waters require different chemicals. Sodium carbonate, sodium aluminate, sodium phosphate, sodium sulphite and compounds of vegetable or inorganic origin are

all used for this purpose. Proprietary chemicals are available to suit various water conditions. The specialist must be consulted to determine the most suitable chemicals to use in each case. Internal treatment alone is not recommended.

External Water Treatment

External treatment is used to remove suspended solids, dissolved solids (particularly the calcium and magnesium ions which are a major cause of scale formation) and dissolved gases (oxygen and carbon dioxide).

The external treatment processes available are: ion exchange; demineralization; reverse osmosis and de-aeration. Before any of these are used, it is necessary to remove suspended solids and colour from the raw water, because these may foul the resins used in the subsequent treatment sections.

Methods of pre-treatment include simple sedimentation in settling tanks or settling in clarifiers with aid of coagulants and flocculants. Pressure sand filters, with spray aeration to remove carbon dioxide and iron, may be used to remove metal salts from bore well water.

The first stage of treatment is to remove hardness salt and possibly non-hardness salts. Removal of only hardness salts is called softening, while total removal of salts from solution is called demineralization.

The processes are:

Ion-exchange process (Softener Plant)

In ion-exchange process, the hardness is removed as the water passes through bed of natural zeolite or synthetic resin and without the formation of any precipitate. The simplest type is ‘base exchange’ in which calcium and magnesium ions are exchanged for sodium ions. The sodium salts being soluble, do not form scales in boilers. Since base exchanger only replaces the calcium and magnesium with sodium, it does not reduce the TDS content, and blowdown quantity. It also does not reduce the alkalinity.

Demineralization is the complete removal of all salts. This is achieved by using a “cation” resin, which exchanges the cations in the raw water with hydrogen ions, producing hydrochloric, sulphuric and carbonic acid. Carbonic acid is removed in degassing tower in which air is blown through the acid water. Following this, the water passes through an “anion” resin which exchanges anions with the mineral acid (e.g. sulphuric acid) and forms water. Regeneration of cations and anions is necessary at intervals using, typically, mineral acid and caustic soda respectively. The complete removal of silica can be achieved by correct choice of anion resin.

Ion exchange processes can be used for almost total demineralization if required, as is the case in large electric power plant boilers

De-aeration

In de-aeration, dissolved gases, such as oxygen and carbon dioxide, are expelled by preheating the feed water before it enters the boiler.

All natural waters contain dissolved gases in solution. Certain gases, such as carbon dioxide and oxygen, greatly increase corrosion. When heated in boiler systems, carbon dioxide (CO2) and oxygen (O2) are released as gases and combine with water (H2O) to form carbonic acid, (H2CO3). Removal of oxygen, carbon dioxide and other non-condensable gases from boiler feedwater is vital to boiler equipment longevity as well as safety of operation.  Carbonic acid corrodes metal reducing the life of equipment and piping.  It also dissolves iron (Fe) which when returned to the boiler precipitates and causes scaling on the boiler and tubes.  This scale not only contributes to reducing the life of the equipment but also increases the amount of energy needed to achieve heat transfer.  De-aeration can be done by mechanical de-aeration, by chemical de-deration or by both together.

Mechanical de-aeration

Mechanical de-aeration for the removal of these dissolved gases is typically utilized prior to the addition of chemical oxygen scavengers. Mechanical de-aeration is based on Charles' and Henry's laws of physics. Simplified, these laws state that removal of oxygen and carbon dioxide can be accomplished by heating the boiler feed water, which reduces the concentration of oxygen and carbon dioxide in the atmosphere surrounding the feed water. Mechanical de-aeration can be the most economical. They operate at the boiling point of water at the pressure in the de-aerator. They can be of vacuum or pressure type.

The vacuum type of de-aerator operates below atmospheric pressure, at about 82oC, can reduce the oxygen content in water to less than 0.02 mg/litre. Vacuum pumps or steam ejectors are required to maintain the vacuum.

The pressure-type de-aerators operates by allowing steam into the feed water through a pressure control valve to maintain the desired operating pressure, and hence temperature at a minimum of 105oC. The steam raises the water temperature causing the release of O2

and CO2 gases that are then vented from the system. This type can reduce the oxygen content to 0.005 mg/litre.

Where excess low-pressure steam is available, the operating pressure can be selected to make use of this steam and hence improve fuel economy. In boiler systems, steam is preferred for de-aeration because:

Steam is essentially free from O2 and CO2,

Steam is readily available Steam adds the heat required to complete the reaction. 

Chemical de-aeration

While the most efficient mechanical deaerators reduce oxygen to very low levels (0.005 mg/litre), even trace amounts of oxygen may cause corrosion damage to a system.  Consequently, good operating practice requires removal of that trace oxygen with a chemical oxygen scavenger such as sodium sulfite or hydrazine.  Sodium sulphite reacts with oxygen to form sodium sulphate, which increases the TDS in the boiler water and hence increases the blowdown requirements and make-up water quality. Hydrazine reacts with oxygen to form nitrogen and water. It is invariably used in high pressures boilers when low boiler water solids are necessary, as it does not increase the TDS of the boiler water.

Reverse Osmosis

Reverse osmosis uses the fact that when solutions of differing concentrations are separated by a semi-permeable membrane, water from less concentrated solution passes through the membrane to dilute the liquid of high concentratio. If the solution of high concentration is pressurized, the process is reversed and the water from the solution of high concentration flows to the weaker solution. This is known as reverse osmosis. The quality of water produced depends upon the concentration of the solution on the high-pressure side and pressure differential ascross the membrane. This process is suitable for waters with very high TDS, such as sea water.

Recommended boiler and feed water quality

The impurities found in boiler water depend on the untreated feed water quality, the treatment process used and the boiler operating procedures. As a general rule, the higher the boiler operating pressure, the greater will be the sensitivity to impurities. Recommended feed water and boiler water limits are shown in Table 2 and Table 3.

Table 2 Recommended Feed Water Limits

Factor Upto 20 kg/cm2 21 - 40 kg/cm2 41 - 60 kg/cm2

Total iron (max) ppm 0.05 0.02 0.01

Total copper (max) ppm 0.01 0.01 0.01

Total silica (max) ppm 1.0 0.3 0.1

Oxygen (max) ppm 0.02 0.02 0.01

Hydrazine residual ppm - - -0.02-0.04

pH at 250C 8.8-9.2 8.8-9.2 8.2-9.2

Hardness, ppm 1.0 0.5 -

.Table 3 Recommended Boiler Water Limits

Factor Upto 20 kg/cm2 21 - 40 kg/cm2 41 - 60 kg/cm2

TDS, ppm 3000-3500 1500-2000 500-750

Total iron dissolved solids ppm 500 200 150

Specific electrical conductivity at 250C (mho)

1000 400 300

Phosphate residual ppm 20-40 20-40 15-25

pH at 250C 10-10.5 10-10.5 9.8-10.2

Silica (max) ppm 25 15 10

7 Energy Conservation Opportunities

The various energy efficiency opportunities in boiler system can be related to combustion, heat transfer, avoidable losses, high auxiliary power consumption, water quality and blowdown.

Examining the following factors can indicate if a boiler is being run to maximize its efficiency:

1. Stack Temperature

The stack temperature should be low as possible. However, it should not be so low that water vapor in the exhaust condenses on the stack walls. This is important in fuels containing signficant sulphur as low temperature can lead to sulphur dew point corrosion. Stack temperatures greater than 200°C indicates potential for recovery of waste heat. It also indicate the scaling of heat transfer/recovery equipment and hence the urgency of taking an early shut down for water / flue side cleaning.

2. Feed Water Preheating using Economiser

Typically, the flue gases leaving a modern 3-pass shell boiler are at temperatures of 200 to 300 oC. Thus, there is a potential to recover heat from these gases. The flue gas exit temperature from a boiler is usually maintained at a minimum of 200 oC, so that the sulphur oxides in the flue gas do not condense and cause corrosion in heat transfer surfaces. When a clean fuel such as natural gas, LPG or gas oil is used, the economy of heat recovery must be worked out, as the flue gas temperature may be well below 200oC.

The potential for energy saving depends on the type of boiler installed and the fuel used. For a typically older model shell boiler, with a flue gas exit temperature of 260 oC, an economizer could be used to reduce it to 200oC, increasing the feed water temperature by

15oC. Increase in overall thermal efficiency would be in the order of 3%. For a modern 3-pass shell boiler firing natural gas with a flue gas exit temperature of 140oC a condensing economizer would reduce the exit temperature to 65oC increasing thermal efficiency by 5%.

3. Combustion Air Preheat

Combustion air preheating is an alternative to feedwater heating. In order to improve thermal efficiency by 1%, the combustion air temperature must be raised by 20 oC. Most gas and oil burners used in a boiler plant are not designed for high air preheat temperatures.

Modern burners can withstand much higher combustion air preheat, so it is possible to consider such units as heat exchangers in the exit flue as an alternative to an economizer, when either space or a high feed water return temperature make it viable.

4. Incomplete Combustion

Incomplete combustion can arise from a shortage of air or surplus of fuel or poor distribution of fuel. It is usually obvious from the colour or smoke, and must be corrected immediately.

In the case of oil and gas fired systems, CO or smoke (for oil fired systems only) with normal or high excess air indicates burner system problems. A more frequent cause of incomplete combustion is the poor mixing of fuel and air at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization on tips and deterioration of diffusers or spinner plates.

With coal firing, unburned carbon can comprise a big loss. It occurs as grit carry-over or carbon-in-ash and may amount to more than 2% of the heat supplied to the boiler. Non uniform fuel size could be one of the reasons for incomplete combustion. In chain grate stokers, large lumps will not burn out completely, while small pieces and fines may block the air passage, thus causing poor air distribution. In sprinkler stokers, stoker grate condition, fuel distributors, wind box air regulation and over-fire systems can affect carbon loss. Increase in the fines in pulverized coal also increases carbon loss.

5. Excess Air Control

The Table 4 gives the theoretical amount of air required for combustion of various types of fuel.

Table 4 Theoretical Combustion Data – Common Boiler Fuels

Fuel kg of air req./kg of fuel

kg of flue gas/kg of fuel

m3 of flue/kg of fuel

Theoretical CO2% in dry flue gas

CO2% in flue gas achieved in practice

Solid Fuels

BagasseCoal (bituminous)LignitePaddy HuskWood

3.210.88.44.65.8

3.4311.79.105.636.4

2.619.406.974.584.79

20.6518.7019.4019.820.3

10-1210-139 -1314-1511.13

Liquid Fuels

Furnace OilLSHS

13.9014.04

14.3014.63

11.5010.79

15.015.5

9-149-14

Excess air is required in all practical cases to ensure complete combustion, to allow for the normal variations in combustion and to ensure satisfactory stack conditions for some fuels. The optimum excess air level for maximum boiler efficiency occurs when the sum of the losses due to incomplete combustion and loss due to heat in flue gases is minimum. This level varies with furnace design, type of burner, fuel and process variables. It can be determined by conducting tests with different air fuel ratios.

Typical values of excess air supplied for various fuels are given in Table –.5

Table 5 Excess Air Levels for Different Fuels

Fuel Type of Furnace or Burners Excess Air (% by wt)

Pulverised coal Completely water-cooled furnace for slag-tap or dry-ash removal

15-20

Partially water-cooled furnace for dry-ash removal

15-40

Coal Spreader stoker 30-60Water-cooler vibrating-grate stokers 30-60Chain-grate and traveling-gate stokers 15-50Underfeed stoker 20-50

Fuel oil Oil burners, register type 15-20Multi-fuel burners and flat-flame 20-30

Natural gas High pressure burner 5-7Wood Dutch over (10-23% through grates) and

Hofft type20-25

Bagasse All furnaces 25-35Black liquor Recovery furnaces for draft and soda-

pulping processes30-40

Controlling excess air to an optimum level always results in reduction in flue gas losses; for every 1% reduction in excess air there is approximately 0.6% rise in efficiency.

Various methods are available to control the excess air:

Portable oxygen analysers and draft gauges can be used to make periodic readings to guide the operator to manually adjust the flow of air for optimum operation. Excess air reduction up to 20% is feasible.

The most common method is the continuous oxygen analyzer with a local readout mounted draft gauge, by which the operator can adjust air flow. A further reduction of 10-15% can be achieved over the previous system.

The same continuous oxygen analyzer can have a remote controlled pneumatic damper positioner, by which the readouts are available in a control room. This enables an operator to remotely control a number of firing systems simultaneously.

The most sophisticated system is the automatic stack damper control, whose cost is really justified only for large systems.

6. Radiation and Convection Heat Loss

The external surfaces of a shell boiler are hotter than the surroundings. The surfaces thus lose heat to the surroundings depending on the surface area and the difference in temperature between the surface and the surroundings.

The heat loss from the boiler shell is normally a fixed energy loss, irrespective of the boiler output. With modern boiler designs, this may represent only 1.5% on the gross calorific value at full rating, but will increase to around 6%, if the boiler operates at only 25 percent output.

Repairing or augmenting insulation can reduce heat loss through boiler walls and piping.

7. Automatic Blowdown Control

Uncontrolled continuous blowdown is very wasteful. Automatic blowdown controls can be installed that sense and respond to boiler water conductivity and pH. A 10% blow down in a 15 kg/cm2 boiler results in 3% efficiency loss.

8. Reduction of Scaling and Soot Losses

In oil and coal-fired boilers, soot buildup on tubes acts as an insulator against heat transfer. Any such deposits should be removed on a regular basis. Elevated stack temperatures may indicate excessive soot buildup. Also same result will occur due to scaling on the water side.

High exit gas temperatures at normal excess air indicate poor heat transfer performance. This condition can result from a gradual build-up of gas-side or waterside deposits. Waterside deposits require a review of water treatment procedures and tube cleaning to

remove deposits. An estimated 1% efficiency loss occurs with every 22oC increase in stack temperature.

Stack temperature should be checked and recorded regularly as an indicator of soot deposits. When the flue gas temperature rises about 20oC above the temperature for a newly cleaned boiler, it is time to remove the soot deposits. It is, therefore, recommended to install a dial type thermometer at the base of the stack to monitor the exhaust flue gas temperature.

Every millimeter thickness of soot coating increases the stack temperature by about 55 oC. It is also estimated that 3 mm of soot can cause an increase in fuel consumption by 2.5%. Periodic off-line cleaning of radiant furnace surfaces, boiler tube banks, economizers and air heaters may be necessary to remove stubborn deposits.

9. Reduction of Boiler Steam Pressure

This is an effective means of reducing fuel consumption, if permissible, by as much as 1 to 2%. Lower steam pressure gives a lower saturated steam temperature and without stack heat recovery, a similar reduction in the temperature of the flue gas temperature results.

Steam is generated at pressures normally dictated by the highest pressure / temperature requirements for a particular process. In some cases, the process does not operate all the time, and there are periods when the boiler pressure could be reduced. The energy manager should consider pressure reduction carefully, before recommending 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.

10. Variable Speed Control for Fans, Blowers and Pumps

Variable speed control is an important means of achieving energy savings. Generally, combustion air control is effected by throttling dampers fitted at forced and induced draft fans. Though dampers are simple means of control, they lack accuracy, giving poor control characteristics at the top and bottom of the operating range. In general, if the load characteristic of the boiler is variable, the possibility of replacing the dampers by a VSD should be evaluated.

11. Effect of Boiler Loading on Efficiency

The maximum efficiency of the boiler does not occur at full load, but at about two-thirds of the full load. If the load on the boiler decreases further, efficiency also tends to decrease. At zero output, the efficiency of the boiler is zero, and any fuel fired is used only to supply the losses. The factors affecting boiler efficiency are :

As the load falls, so does the value of the mass flow rate of the flue gases through the tubes. This reduction in flow rate for the same heat transfer area, reduced the exit flue gas temperatures by a small extent, reducing the sensible heat loss.

Below half load, most combustion appliances need more excess air to burn the fuel completely. This increases the sensible heat loss.

In general, efficiency of the boiler reduces significantly below 25% of the rated load and as far as possible, operation of boilers below this level should be avoided.

12. Proper Boiler Scheduling

Since, the optimum efficiency of boilers occurs at 65-85% of full load, it is usually more efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a large number at low loads.

13. Boiler Replacement

The potential savings from replacing a boiler depend on the anticipated change in overall efficiency. A change in a boiler can be financially attractive if the existing boiler is :

old and inefficient not capable of firing cheaper substitution fuel over or under-sized for present requirements not designed for ideal loading conditions

The feasibility study should examine all implications of long-term fuel availability and company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied.

8 Case Study

Installing Boiler Economiser

A paper mill retrofitted an economiser to existing boiler. The general specification of the boiler is given below:

Boiler Capacity (T/h)

Feed Water Temp (oC)

Steam Pressure (bar)

Fuel oil

8 110 18 Furnace oil

The thermal efficiency of the boiler was measured and calculated by the indirect method using flue gases analyser and data logger. The result is summarised below:

Thermal efficiency : 81%Flue gas temperature : 315oCCO2 % : 13

CO (ppm) : 167

The temperature in the flue gas is in the range of 315 to 320oC. The waste heat in the flue gas is recovered by installing an economizer, which transfers waste heat from the flue gases to the boiler feed water. This resulted in a rise in feed water temperature by about 26oC.

Basic Data

Average quantity of steam generated .... . : 5 T/hr

Average flue gas temperature ................ : 315 oC

Average steam generation / kg of fuel oil .: 14 kg

Feed water inlet temperature ................. : 110oC

Fuel oil supply rate................................ : 314 kg/hr

Flue gas quantity ................................... : 17.4 kg/kg of fuel

Cost Economics

Quantity of flue gases ............................. : 314 x 17.4 = 5463.6 kg/h

Quantity of heat available in the : 5463.6 x0.23 x(315-200) = 144512 kCal/h flue gases

Rise in the feed water temperature ...........: 26 oC.

Heat required for pre-heating the : 5000 x 1 x 26 = 130000 kCal/h feed water

Saving in terms of furnace oil .....................: 130000/10000 = 13 kg/h

Annual operating hours ........................... .: 8600

Annual savings of fuel oil .........................: 8600 x 13 = 111800 kg

Conclusion

Through recovery of waste heat by installation of an economizer, the paper mill was able to save 13 kg/hr. of furnace oil, which amounts to about 1,11,800 kg of furnace oil per annum.

CHECKLIST & TIPS FOR ENERGY EFFICIENCY

Boilers

Preheat combustion air with waste heat.

(22 0C reduction in flue gas temperature increases boiler efficiency by 1%)

Use variable speed drives on large boiler combustion air fans with variable

flows.

Burn wastes if permitted.

Insulate exposed heated oil tanks.

Clean burners, nozzles, strainers, etc.

Inspect oil heaters for proper oil temperature.

Close burner air and/or stack dampers when the burner is off to minimize heat

loss up the stack.

Improve oxygen trim control (e.g. -- limit excess air to less than 10% on clean

fuels).

(5% reduction in excess air increases boiler efficiency by 1% or: 1% reduction of

residual oxygen in stack gas increases boiler efficiency by 1%)

Automate/optimize boiler blowdown. Recover boiler blowdown heat.

Use boiler blowdown to help warm the back-up boiler.

Optimize deaerator venting.

Inspect door gaskets.

Inspect for scale and sediment on the water side.

(A 1 mm thick scale (deposit) on the water side could increase fuel

consumption by 5 to 8%.)

Inspect for soot, flyash, and slag on the fire side.

(A 3 mm thick soot deposition on the heat transfer surface can cause an increase in fuel

consumption to the tune of 2.5%)

Optimize boiler water treatment.

Add an economizer to preheat boiler feedwater using exhaust heat.

Recycle steam condensate.

Study part-load characteristics and cycling costs to determine the most-

efficient mode for operating multiple boilers.

Consider multiple or modular boiler units instead of one or two large boilers.

Establish a boiler efficiency-maintenance program. Start with an energy audit

and follow-up, then make a boiler efficiency-maintenance program a part of

your continuous energy management program.

Steam System

Fix steam leaks and condensate leaks.

(A 3 mm diameter hole on a pipe line carrying 7 Kg/cm2 steam would waste

33 Kilo litres of fuel oil per year)

Accumulate work orders for repair of steam leaks that can't be fixed during

the heating season due to system shutdown requirements. Tag each such leak

with a durable tag with a good description.

Use back pressure steam turbines to produce lower steam pressures.

Use more-efficient steam desuperheating methods.

Ensure process temperatures are correctly controlled.

Maintain lowest acceptable process steam pressures.

Reduce hot water wastage to drain.

Remove or blank off all redundant steam piping.

Ensure condensate is returned or re-used in the process.

(60C raise in feed water temperature by economiser/condensate recovery

corresponds to a 1% saving in fuel consumption, in boiler)

Preheat boiler feed-water.

Recover boiler blowdown.

Check operation of steam traps.

Remove air from indirect steam using equipment

(0.25 mm thick air film offers the same resistance to heat transfer as a 330 mm thick

copper wall)

Inspect steam traps regularly and repair malfunctioning traps promptly.

Consider recovery of vent steam (e.g. -- on large flash tanks).

Use waste steam for water heating.

Use an absorption chiller to condense exhaust steam before returning the

condensate to the boiler.

Use electric pumps instead of steam ejectors when cost benefits permit

Establish a steam efficiency-maintenance program. Start with an energy audit

and follow-up, then make a steam efficiency-maintenance program a part of

your continuous energy management program.

CHAPTER 9- MAINTENANCE ACTIVITIES FOR BOILERS

9-1. Minimum maintenance activities for boilersThe tables located at the end of this chapter indicate items that must be performed to maintain systems and equipment at a minimum level of operational readiness. The listed minimum action items should be supplemented by manufacturer-recommended maintenance activities and procedures for specific pieces of equipment. Maintenance actions included in this section are for various modes of operation, subsystems, or components. Table 9-1 provides maintenance information for packaged heating boilers. Table 9-2 provides maintenance information for boiler system instrumentation and electrical systems.

9-2. General maintenance for boilersThis section presents general instructions for maintaining the types of components associated with boilers. Exercise valves. Exercise all valves in the heating boiler system.

(1) Inspect packing gland and tighten if necessary.(2) Check for correct positioning and operation.(3) Check for leaking seals.(4) Adjust operator linkages and limit switches on control valves.

Test alarms. Verify that the horns sound and all annunciator lights illuminate by pressing the appropriate test push buttons. Press the ACKNOWLEDGE and RESET push buttons when proper operation has been confirmed.

Lubricate rotating equipment. Grease all zerks at the manufacturer-recommended service interval. Grease gently with a handgun to avoid damage to grease seals. Do not overgrease.

(1) Ball or roller bearings tend to heat up when overgreased and will cool down to normal running temperatures when the excess grease either oozes out or is wiped off. The normal operating temperature of a bearing may be well above 140°F, which is "hot" to touch. Temperatures should be checked with a thermometer and any temperature readings over 180°F should be questioned. If a drop of water placed on a bearing sizzles, the bearing is in distress and should be changed before it seizes and ruins the shaft. For sleeve bearing assemblies with oil reservoirs, service reservoirs at manufacturer-recommended interval with recommended viscosity lubricating oil. Do not overfill reservoir as overheating may result. When new sleeve bearing units are placed in service, drain and flush the oil reservoir after about two weeks of operation and refill the reservoir with new lubricating oil of the proper viscosity.

(2) During equipment overhauls, bearing assemblies should be thoroughly cleaned, inspected, and adjusted in accordance with the manufacturer's recommendations. All old grease should be removed from bearings and

the bearings repacked with grease a minimum of every two years. Monitor the operation of all recently installed bearings. Check for overheating (alignment, lubrication), vibration (alignment), loose collars, fasteners, etc. Early problem detection can avoid early failure and costly replacement.

Belt drives. When belt replacement is required replace multiple belts as a set. Loosen drive motor mounting, and slide motor toward driven shaft so that belts may be installed by laying belts onto pulleys. Do not lever belts onto pulleys. Check belt tension several times during first 48 hours that new belts are in operation, and adjust belt tension as required.

(1) When belt tension adjustment is required, consult the belt manufacturer's literature for the proper tension force (and belt deflection to achieve that force). Deflect each belt at the midpoint between the pulleys to the deflection recommended, and read the belt tension. Adjust the tension as required. Many belts have an initial run-in period tension (usually about 48 hours) and then a broken-in tension. Generally, if the tension reading differs more than 2 pounds from the recommended reading, the belt tension should be adjusted. If a belt tension-measuring device is not available, belt tension may be checked by observing the deflection when pressing down on each belt at about the midpoint between the pulleys. If the tension is correct, the belt deflection will be about one belt thickness for each 4 feet of center-to-center distance between the pulleys. Caution should be used in using this method because there are many different belt designs available for the same service and each belt design may have different tension and deflection characteristics. To tension the belts, loosen the motor hold-down bolts. Move the motor away from the driven shaft to increase the tension and toward the driven shaft to decrease the tension. (If the motor is on a slide base, it will not be necessary to loosen the motor hold-down bolts. Adjustment is accomplished using the slide base positioning screw.) Tighten the motor hold-down bolts. Run the equipment for a short period of time, and then check the belt tension.

(2) When drive alignment is required, lay a straightedge across both the driver and driven pulleys. The straightedge should contact each pulley in two places. If the pulleys are not aligned, verify that the drive shaft and driven shaft are parallel. If the shafts are not parallel, adjust the motor so the shafts are parallel. When the shafts are parallel, adjust the positions of the pulleys on the shafts to achieve alignment. Verify that the driven pulley is in the correct position on the driven shaft and that the pulley is firmly locked in place. Loosen the pulley on the motor shaft, and move the pulley into alignment with the driven pulley. Tighten the pulley on the shaft, install and tension the drive belts, and run the equipment for a short period of time. Check drive alignment and adjust as required.

Packing adjustment. Occasional packing adjustment may be required to keep leakage to a slight weep; if impossible to reduce leakage by gentle

tightening, replace packing. A slight weeping through the packing gland is required so that the process fluid provides lubrication for the packing material. Maintain a supply of the recommended type and size of packing required for the equipment. Do not substitute one type of packing with another without verifying the packing types are compatible. Do not use oversized packing. If diameter of oversized packing is reduced by hammering, early failure of packing may result. A too tight packing joint may interfere with equipment operation, can damage equipment, and, again, may result in early failure of the packing. The procedure to follow when replacing packing is as follows.

(1) Remove all old packing.(2) Inspect shaft for wear and replace as required.(3) Use proper size packing and cut packing into rings using the shaft as a

guide. When cutting to length, hold packing tightly around shaft but do not stretch packing. Cut with a butt joint. Do not wind packing around shaft.

(4) Thoroughly clean shaft and housing.(5) Install one ring at a time. Oil or grease lubrication, if permitted, will assist

when packing the ring into the box. Offset joints of each succeeding ring by at least 90 degrees from the previous ring.

(6) If shaft is equipped with a lantern ring, be sure that lantern ring is slightly behind lubrication hole in stuffing box; otherwise, the lantern ring will move forward when the gland is taken up and the packing behind the ring may plug the lubrication hole.

(7) Tighten the gland bolts all the way to seat the packing. Then loosen the nuts until the nuts are finger tight. In most applications, newly installed packing should be allowed to leak freely on startup. After startup, tighten packing gland until only 2 to 3 drops a second are leaking. Do not try to stop leakage entirely. The leakage lubricates the packing and prevents early failure of the packing and shaft.

Mechanical seals. There are many different mechanical seal designs. As a result, there is no standard procedure for maintaining and installing mechanical seals. Mechanical seal installations commonly fail because the seal was not placed in the correct position. Seal faces may wear rapidly resulting in early seal failure if the spring has too much initial compression. This results in too much force between the faces of the seal, which does not allow proper lubrication of the surfaces. Alternately, if the spring has too little initial compression, the seal faces separate at normal operating pressures and leak.

It is important that manufacturer's information for the seals used be obtained and closely followed. In general, there are four critical requirements in any seal installation as follows.

(1) Determine that the equipment is ready to have the seal installed, shaft and seal housing have been inspected and repaired as required, and the components have been thoroughly cleaned.

(2) Place the seal in the correct position for the right operating length (consult manufacturer's data).

(3) Prevent damage to seal rings.(4) Prevent damage to seal faces.

Clean all equipment. Clean equipment is easier to inspect, lubricate, and adjust. Clean equipment also runs cooler and looks better.

Safety relief valve test (steam boilers). As precautionary measures, all personnel concerned with conducting a pop or capacity test should be briefed on the location of all shutdown controls in the event of an emergency, and there should be at least two people present. Care should be taken to protect those present from escaping steam.

(1) Every 30 days that the boiler is in operation or after any period of inactivity, a try lever test should be performed as follows. With the boiler under a minimum of 5 psi pressure, lift the try lever on the safety valve to the wide open position and allow steam to be discharged for five seconds to 10 seconds. Release the try lever, and allow the spring to snap the disk to the closed position. If the valve simmers, operate the try lever two or three times to allow the disk to seat properly. If the valve continues to simmer, it must be replaced or repaired by an authorized representative of the manufacturer. Inspect the valve for evidence of scale or encrustation within the body. Do not disassemble valve or attempt to adjust the spring setting. It is advisable to have a chain attached to the try lever of the valve to facilitate this test and allow it to be conducted in a safe manner from the floor. The date of this test should be entered into the boiler logbook. (2) A pop test of a safety valve is conducted to determine that the valve will open under boiler pressure within the allowable tolerances. It should be conducted annually, preferably at the beginning of the heating season if the boiler is used only for space heating purposes. Hydrostatic testing (using water) is not to be considered an acceptable test to check safety valve opening pressure. A recommended procedure is as follows.

Establish necessary trial conditions at the particular location. Where necessary, provide adequately supported temporary piping from the valve discharge to a safe location outside the boiler room. In some installations, temporary ventilation may dispose of the steam vapor satisfactorily. Review preparation for test with personnel involved. All such tests should have at least two people present.

Install temporary calibrated test pressure gauge to check accuracy of boiler gauge.

Isolate the boiler by shutting the stop valves in the steam supply and condensate return piping.

Temporarily place jumper leads across the appropriate terminals on the operating control to demonstrate the ability of the high-limit pressure control to function properly. After this has been checked, place another

set of jumper leads across the high-limit pressure control terminals to permit continuous operation of the burner.

The safety valve should pop open at an acceptable pressure, i.e., 15 psi ±2 psi. A simmering action will ordinarily be noticed shortly before the valve pops to the open position.

If the valve does not open in the 13 psi to 17 psi range, it should be replaced. It is not necessarily a dangerous situation if the valve opens below 13 psi, but it could indicate a weakening of the spring, improper setting of the spring, etc. If the valve does not open at 17 psi, shut off the burner and dissipate the steam to the system by slowly opening the supply valve.

If the valve pops open at an acceptable pressure, immediately remove the jumper leads from the high-limit pressure control. The burner main flame should cut off as soon as the jumper leads are removed.

The safety valve will stay open until the pressure drops sufficiently in the boiler to allow it to close, usually 2 psi to 4 psi below the opening pressure. This pressure drop (blowdown) is usually indicated on the safety valve nameplate.

Relieve the higher pressure steam to the rest of the system by slowly opening the steam supply valve. After the boiler and supply piping pressures have become equalized, open the return valve.

Remove the jumper leads from the operating control and check to make certain that it functions properly. This is best done by allowing it to cycle the burner on and off at least once.

Enter the necessary test data into the boiler logbook.

Safety relief valve test (water boilers). At try lever, test and pop test should be performed for water boilers as described below.

(1) Every 30 days that the boiler is in operation or after any prolonged period of inactivity, a try lever test should be performed as follows.

Prior to the test, check the safety relief discharge piping to make sure it

is installed and supported so this test does not transmit any stress or strain to the body of the safety relief valve.

Check and log the operating pressure and temperature of the system. Shut off circulating pump and fuel burning equipment. Isolate the boiler from the system, leaving the expansion tank valve and

the automatic fill valve open. With the boiler at operating pressure, lift the try lever to the full open

position and hold it open for at least five seconds or until clean water is discharged.

Release the lever and allow the spring to snap to the closed position. If the valve leaks, operate the try lever two or three times to clear the seat of any foreign matter that is preventing proper seating. As safety relief

valves are normally piped to the floor or near a floor drain, it may take some time to determine if the valve has shut completely.

If the safety relief valve continues to leak, it must be replaced before the boiler is returned to operation.

After it has been determined that the safety relief has shut completely, add water to the boiler until the pressure rises to the initial pressure which was logged at the start of the test.

Open the valves to the system. Start the circulating pump. Start the fuel burning system. Observe the pressure and temperature until the system returns to

operating conditions and operating control has cycled the burner on and off at least once.

Check again to ensure that the safety relief valve is not leaking.

(2) A pop test (pressure relief valve) should be performed annually, preferably at the beginning of the heating season, if the boiler is shut off during the summer months. The following procedure should be reviewed by the person in charge of the test with at least one other person, and trial conditions should be determined.

Isolate the boiler from the rest of the heating system by closing the supply and return valves. On large water content boilers, the expansion tank may also be isolated to speed up pressure rise.

Check the safety relief valve discharge piping to make sure it is installed and supported so that this test does not transmit any detrimental stress to the body of the safety relief valve.

Temporarily install a calibrated pressure gauge and thermometer to check the accuracy of the boiler pressure gauge and thermometer or remove gauge and thermometer and check calibration and reinstall prior to test.

Perform a try lever test prior to the beginning of the pop test. Check and log the system operating pressure and temperature. Shut off circulating pump and fuel burning equipment. If an automatic water feeder is provided, close the boiler water inlet

valve. Turn on the fuel burning equipment. Place jumper leads across the appropriate terminals of the operating

temperature control and check the operation of the high-temperature cutout.

If the high-temperature cutout functions properly, place jumper leads across the appropriate terminals of the high-temperature cutout to permit continuous operation of the burner.

Make sure that all personnel are clear of the safety relief valve discharge. On boilers having a small water storage capacity, very little heat will be required to raise the boiler pressure to the popping pressure of the safety relief valve.

The safety relief valve should open within an acceptable range above or below the set point. This range is ±2 psi for valves set to open at 70 psi or less and ±3 percent of set pressure for valves set to open at more than 70 psi.

If the safety relief valve does not open at the set pressure plus the allowable tolerance, shut off the fuel burning equipment and do not operate the boiler until the safety relief valve has been replaced.

Observe the rising pressure and temperature of the boiler, and log the pressure at which the safety relief valve opens. As soon as the safety relief valve opens, turn off fuel burning equipment by removing jumper leads and record safety relief valve closing pressure.

If the safety relief valve opens at a pressure below the allowable tolerance, this is not necessarily a dangerous condition, but it can indicate a deteriorating condition or improper spring setting.

The valve should be replaced. When the safety relief valve opens, it will discharge a mixture of

water and vapor. The valve will remain open until a closing pressure is reached. This pressure may be 20 percent to 50 percent below the set pressure of the valve. There are no blowdown tolerance requirements for safety relief valves.

After the safety relief valve has closed, add water to the boiler, if necessary, until the boiler pressure rises to the initial system operating pressure that was logged at the start of the test.

Open the supply and return valves to the system and expansion tank valve, if closed, and open the boiler water inlet valve if an automatic water feeder is provided.

Start the circulating pump. Start the fuel burning equipment. Observe the pressure and temperature until the system returns to

operating conditions and the operating control has cycled the burner on and off at least once.

Check again to ensure that the safety relief valve is not leaking.

Is Preventive Maintenance Necessary?

Reliability Centered Maintenance has changed the way we think about Preventive Maintenance (PM). It has caused some to question whether it is even necessary to do preventive maintenance. The truth is most manufacturing facilities would benefit from a good preventive maintenance program. It would be especially beneficial for those plants that rely on breakdown or run-to-failure maintenance. But, a preventive maintenance program is potentially risky, so it must be administered and performed properly to be successful. This paper will examine both the benefits and risks of preventive maintenance and offer some ideas on how to make it successful. We will start with a definition of preventive maintenance.

What is Preventive Maintenance?

Preventive maintenance is planned maintenance of plant and equipment that is designed to improve equipment life and avoid any unplanned maintenance activity. PM includes painting, lubrication, cleaning, adjusting, and minor component replacement to extend the life of equipment and facilities. Its purpose is to minimize breakdowns and excessive depreciation. Neither equipment nor facilities should be allowed to go to the breaking point. In its simplest form, preventive maintenance can be compared to the service schedule for an automobile.

A bona fide preventive maintenance program should include:

Non-destructive testing

Periodic inspection

Preplanned maintenance activities

Maintenance to correct deficiencies found through testing or inspections.

The amount of preventive maintenance needed at a facility varies greatly. It can range from a walk through inspection of facilities and equipment noting deficiencies for later correction up to computers that actually shut down equipment after a certain number of hours or a certain number of units produced, etc.

Many reasons exist for establishing a PM program. Listed below are a few of these. Whenever any of these reasons are present, a PM program is likely needed.

Reasons for Preventive Maintenance

Increased Automation

Business loss due to production delays

Reduction of insurance inventories

Production of a higher quality product

Just-in-time manufacturing

Reduction in equipment redundancies

Cell dependencies

Minimize energy consumption (5% less)

Need for a more organized, planned environment

Why Have a PM Program

The most important reason for a PM program is reduced costs as seen in these many ways:

Reduced production downtime, resulting in fewer machine breakdowns.

Better conservation of assets and increased life expectancy of assets, thereby eliminating premature replacement of machinery and equipment.

Reduced overtime costs and more economical use of maintenance workers due to working on a scheduled basis instead of a crash basis to repair breakdowns.

Timely, routine repairs circumvent fewer large-scale repairs.

Reduced cost of repairs by reducing secondary failures. When parts fail in service, they usually damage other parts.

Reduced product rejects, rework, and scrap due to better overall equipment condition.

Identification of equipment with excessive maintenance costs, indicating the need for corrective maintenance, operator training, or replacement of obsolete equipment.

Improved safety and quality conditions.

If it cannot be shown that a preventive maintenance program will reduce costs, there is probably no good reason other than safety to have a PM program.

The Law of PM Programs: There are many advantages for having a good preventive maintenance program. The advantages apply to every kind and size of plant. The law of PM programs is that the higher the value of plant assets and equipment per square foot of plant, the greater will be the return on a PM program. For instance, downtime in an automobile plant assembly line at one time cost $10,000 per minute. Relating this to lost production time an automobile manufacturer reported that the establishment of a PM program in their 16 assembly plants reduced downtime from 300 hours per year to 25 hours per year. With results such as this no well-managed plant can afford not to develop a PM program.[1]

Preventive Maintenance Program Risks

As mentioned in the beginning of this report, preventive maintenance does involve risk. The risk here refers to the potential for creating defects of various types while performing the PM task. In other words, human errors committed during the PM task and infant mortality of newly installed components eventually lead to additional failures of the equipment on which the PM was performed. Frequently, these failures occur very soon after the PM is performed. Typically, the following errors or damage occur during PM’s and other types of maintenance outages.

Damage to an adjacent equipment during a PM task.

Damage to the equipment receiving the PM task to include such things as:

o Damage during the performance of an inspection, repair, adjustment, or installation of a replacement part.

o Installing material that is defective, incorrectly installing a replacement part, or incorrectly reassembling material.

Reintroducing infant mortality by installing new parts or materials.

Damage due to an error in reinstalling equipment into its original location.

Especially disturbing about these types of errors is the fact that they go unnoticed – until they cause an unplanned shutdown. There is some published data that illustrates this point. It comes from the fossil-fuel power industry.

A review of the data from fossil-fueled power plants that examined the frequency and duration of forced outages after a planned or forced maintenance outage reinforces this concept. That data showed that of 3146 maintenance outages, 1772 of them occurred in less than one week after a maintenance outage.

Clearly, this is pretty strong evidence that suggests that in 56% of the cases, unplanned maintenance outages were caused by errors committed during a recent maintenance outage.

Having performed and supervised many industrial PM’s, I also support this concept. I can remember many instances where it would take days after a PM was performed to get everything back to normal. This was particularly true when many components that came in contact with the product being produced were replaced. I remember working with the quality people on many occasions to insure that every position on a multiple position machine was once again producing first quality product. Many times it required adjusting and/or replacing components that were adjusted or replaced on the PM.

How to Have a Successful PM Program

The key to a successful Preventive Maintenance (PM) program is scheduling and execution. Scheduling should be automated to the maximum extent possible. Priority should be given to preventive maintenance and a very aggressive program to monitor the schedule and ensure that the work is completed according to schedule should be in place.

Preventive Maintenance Execution: Traditional preventive maintenance was based on the concept of the bathtub curve. That is, new parts went through three stages, an infant mortality stage, a fairly long run stage, and a wear-out stage. The PM concept was to replace these parts before they entered the wear-out phase. Unfortunately, Reliability Centered Maintenance based on research done by United Airlines and the rest of the aircraft industry showed that very few non-structural components exhibit bathtub curve characteristics. Their research showed that only about 11% of all components exhibit wear-out characteristics, but 72% of components do exhibit infant mortality characteristics. These same characteristics have been shown to apply in Department of Defense systems as well as power plant systems. It is very likely that they apply universally as well. Therefore, they should be taken into account when configuring preventive maintenance on industrial equipment.

In order to have a successful PM program, the message is clear. The PM should focus on cleaning, lubrication, and correcting deficiencies found through testing and inspections. When there is a need to adjust or replace components, it should be done by highly trained and motivated professionals. Predetermined parts replacement should be minimal and done only where statistical evidence clearly indicates wear-out characteristics. In the absence of data to support component replacement, an age exploration program or the collection of data for statistical analysis to determine when to replace components should be initiated. Borrowing from the Japanese, lubrication points should be clearly marked with bright red circles to ensure that lubrication tasks are not missed. Cleaning should be carried our to remove dust, dirt, and grime because these things mask defects that can cause unplanned maintenance outages.

Motivating Preventive Maintenance Workers: A quality preventive maintenance program requires a highly motivated preventive maintenance crew. To provide proper motivation, the following activities are suggested:

Establish inspection and preventive maintenance as a recognized, important part of the overall maintenance program.

Assign competent, responsible people to the preventive maintenance program.

Follow-up to assure quality performance and to show everyone that management does care.

Provide training in precision maintenance practices and training in the right techniques and procedures for preventive maintenance on specific equipment.

Set high standards.

Publicize reduced costs with improved up-time and revenues, which are the result of effective preventive maintenance.

In addition to explaining the importance of a good preventive maintenance program and the benefits that can be derived from it, training is probably the most effective motivational tool available to the maintenance supervisor. Maintenance and training professionals have estimated that a company should spend $1200 per year for training of supervisors and $1000 per year for each craftsperson. In fact, due to advances in technology, if the company has not provided any training for craftspeople in the past 18 months, their skills have become dated.

Preventive & Predictive Maintenance

If you ask ten people what their definition of Preventive Maintenance is, you will get ten different answers. The tasks range from very simple to fairly complex. What's more, the manner in which they are performed and the depths to which they are carried out vary considerably. For the purpose of this guide to Preventive Maintenance (PM) and Predictive Maintenance (PDM), I will use the following definition: PM and PDM are a series of tasks and company policies that, if followed, improve and keep business profits as high as possible. This is achieved by adhering to three general guidelines.

Maintain the production equipment and plant utility systems equipment as close to brand new condition as possible and have all equipment ready to start up and run with no unplanned shutdowns.

Maintain the production equipment and plant utility systems equipment in the best possible operating condition for the purpose of producing quality manufactured goods while the machines are in service.

Complete all PM and PDM work on a regularly scheduled basis without exceeding the "Point of Diminishing Returns on Investment" for the labor, tools and materials required to perform the work.

The difference between Preventive and Predictive Maintenance is that Preventive Maintenance tasks are completed when the machines are shut down and Predictive Maintenance activities are carried out as the machines are running in their normal production modes.

Conclusion

It is possible to have a successful preventive maintenance program. From a cost reduction viewpoint it is essential, but it does entail risk. When the proper care is taken, the risks, however, can be minimized. In order to minimize risk, preventive maintenance has to be carefully planned and carried out by well-trained and motivated workers. The biggest benefits of a PM program occur through painting, lubrication, cleaning and adjusting, and minor component replacement to extend the life of equipment and facilities.

FEED WATER QUALITY FORFEED WATER QUALITY FOR EFFICIENT GENERATION OF STEAMEFFICIENT GENERATION OF STEAM

Presented by

Thermax Limited

BOILER FEED WATER

Boilers are used for converting water into steam by evaporation in the boiler. Only the watergets evaporated and solids dissolved in the water remain in the residual water.

Apart from getting converted into steam, water has another very important function in the boiler,which is to keep the heat exchanger portions cooled and healthy. To ensure that the waterbehaves as a proper cooling medium it is essential to see that

1. The water continuously wets the heating surfaces.

2. The water does not corrode the heating surfaces.

3. The water does not erode the heating surfaces.

4. The water has necessary chemicals within it such that a protective oxide layer is formed onthe surfaces.

In the operation of the boiler it is of primary importance to have water in the proper condition.Almost in all cases it is necessary to treat the water to obtain the correct operating conditions asraw water almost always contains undesirable impurities.

IMPURITIES IN WATER

Impurities in water are found either in the form of dissolved salts and gases or as undissolvedsuspensions. Undissolved suspensions usually lead to erosion and need to be removed by properfiltration. The dissolved salts need chemical processing for control. The dissolved gases mayneed thermal, mechanical or chemical treatment. The treatment will depend on the extent ofimpurities present in the water.

The impurities are measured by evaluating the concentration of the various salts. Whileexpressing the concentration of the various salts it becomes necessary to use a unit ofmeasurement which is interchangeable between the various salts- Thus unless specificallymentioned otherwise, the concentrations of boiler water impurities are taken as milligrams of thesalts expressed in terms ofCaC03 per liter of the solution. This also approximately correspondsto ppm (parts per million) ofCaCO3.

Effect of various impurities in boiler water :

a) Hardness

Most of the calcium and magnesium salts present in the water are collectively called hardness.Calcium carbonate, Magnesium .silicate etc- are typical salts which create problems in the boiler

by forming sludge. Calcium sulphate, calcium silicate and calcium carbonate form scales on theevaporating surfaces. Scales not only restrict heat transfer but also prevent the cooling action ofwater, thus overheating the tubes. In serious cases of scale formation the tubes can overheat tosuch an extent that these may burst under steam pressure. Hardness is measured in terms of mg/las CaCO3.

b) Acidity

Acidity in water induces corrosion of metallic surfaces. Highly acidic water dissolves metals andcauses general wastage of tubes. The consequent thinning of the tubes eventually results in atube burst under steam pressure. Mildly acidic water hastens pitting and oxygen corrosion. Suchtubes eventually puncture. Acidity is measured in terms of pH value.

c) Oxygen

Water at room temperature always contains oxygen dissolved from air. Oxygen promotescorrosion. The rate of wastage and thinning of tubes in highly acidic water is enhanced heavilyby the presence of oxygen. Heavy pitting occurs in the presence of oxygen in mildly acidic oreven in mildly alkaline water, eventually puncturing the tube.

Oxygen is released from water on heating. The oxygen thus released may again dissolve in thepipelines and other equipment inducing corrosion in those areas, unless it is vented out. Oxygenis measured in terms of mg/1 as O2.

d) Total dissolved solids (TDS)

All the salts dissolved in the water are together accounted against total dissolved solids. Theeffect of the total dissolved sol ids in feed water depends on the type of salt and the type of boiler.The effect is also complex due to the mutual action between the various salts. Generally,presence of chlorides, iron salts, etc. accelerate corrosion. Presence of other salts may increasefoaming and priming resulting in expansion of water volume and consequent carry-over. Suchsituations can also bring about heavy water level fluctuations in the boiler aggravating theproblem. A high TDS in the boiler water will also increase steam contamination to the carry-over water having higher amount of salts.

The TDS is measured in terms of mg/1 as CaC03.

An approximate value of the TDS in mg/1 can be obtained by measuring the electricalconductivity in micro Siemens/cm .

e) TurbidityTurbidity is an indicator of undissolved solids. Turbid water may induce erosion. Theundissolved solids also impair proper circulation of water on the heating surfaces which in turncan reduce the cooling action of the water. The undissolved solids may deposit in the lowvelocity regions impairing heat transfer and consequent overheating of the surfaces.

The turbidity is measured in mg/1.

f) Dissolved Carbon dioxide

Dissolved free carbon dioxide appears in the water in the form of carbonic acid. This iscorrosive. Often this is termed as free carbon di-oxide.

The bicarbonate salts present in the water is often considered as bound carbon dioxide in thewater. Carbon dioxide being a gas separates out of water on heating.

The carbon dioxide released from the water gels carried away along with steam and when thesteam condenses the CO2 re-dissolves in the condensate forming carbonic acid. This acidcorrodes pipelines and other user equipment.Carbon dioxide is measured as mg/1 as CO2.

g) Organic matter

Usually the main source of organic matter in the boiler water is oil and grease within the boiler,pipelines, pumps etc. Organic matter can also get into water from leaks in the user equipment ifcondensate from heat exchangers having organic matter is returned.

It is difficult to predict the effect of organic matter in water as it depends on the exact nature.Oils and greases induce foaming and priming and consequently water level fluctuations andcarry-over.

h) Silica

Silica is detrimental mainly due to carry-over along with steam in high pressure boilers. Themain problem being condensation and formation of silicates on turbine blades and such othermoving parts. In lower pressure boilers Silica does not present severe problems except that itmay induce the formation of sodium iron silicates and sodium aluminium silicates which ;in-hard scales.

ALLOWABLE LIMITS OF IMPURITIES

As seen above, impurities in the boiler water create problems in the operation and reduce the lifeof the boiler as well as the connected equipment. Therefore, the allowable limits of impuritieswill depend on what results we are looking for during the operation. Taking into considerationthe general operating conditions and requirements of boiler operation and steam usage. variousNational Standards have been formulated by various countries pulling together the collectiveexperience of boiler operation. The feed water quality standards as well as the boiler waterquality standards derived by all countries are almost the same.

An extract of the Indian Standard IS 10392-1982 is given below for ready reference as anexample.

BFW NORMS

Parameter 0-20(kg/cm2)

20-40(kg/cm2)

Purpose

pH 8.5-9.5 8.5-9.5 Corrosion Control

Oxygen ND ND Pitting Control

Total Hardness <5 ND Scaling Control

Organics ND ND Foam Control

BOILER WATER NORMS

Parameter 0-20(kg/cm2)

20-40(kg/cm2)

Purpose

pH 11-12 11-12 Corrosion

Total Hardness ND ND Scale

Total Alkalinity (20% of TDS)

700 400 Foam

Phenolphthalin Alkalinity (10% of TDS)

350 200 Foam

Silica (40% Caustic Alkaly)

140 80 Scale

TDS 3500 2000 Corrosion

Phosphates 20-40 10-30 Corrosion

Sulphite 30-50 20-40 Oxygen

Hydrazine 0.1 0.1-0.5 Oxygen

NOTE 1:

Recovery Boilers - The boiler feed water used should be completely demineralised and also theboiler feed water and boiler water should be conditioned in accordance with high pressure boilersworking at 5.9 MN/m2 (60 kg/cm2) and above (see IS : 43343 - 1967).

NOTE 2:

When feed water heaters are of copper or copper alloy constructions, the pH of the feed watershould be maintained between 8.5 and 9.2 while when feed water heaters are of iron construction,the pH of the feed may be maintained between 8.5 and 9.5.

NOTE 3:Silica in Boiler Water- Lower concentration of silica may be advisable for steam of turbines, whichgenerally require less than 0.02 mg/1 silica in steam.

* Total alkalinity should preferably be about 20% of total dissolved solids.

** Shall not apply if reducing agents other than sodium sulphite are used.

# For shell type boilers depending on parameters, the limits can be relaxed.

One MN/m2 is approximately 9.8 kg/cm2.

As the above standard is made considering the most usual situations in mind we can expect a goodlife from the boiler if these specifications are met. However depending on the specific needs of theuser some modifications may be made. This depends entirely on the specific experience of the user with respect to his specific circumstances- In cases where it does not matter whether there is heavywater fluctuations or carry-over, perhaps the TDS can be somewhat more than specified above provided the salts contributing to the TDS are not corrosive.

Many shell boiler users operate with a boiler water TDS of 5000 mg/1 without any adverse effects.When the salts in the feed water are of non-corrosive and non-scale forming nature, it may bepossible to operate coil boilers even with 10,000 mg/1 TDS in the blow down water if carry-over & wetness are of no consequence to the user.

TREATMENT OF THE WATER

How do we get rid of the offending impurities in the water and ensure the quality requirement asgiven by the standard specifications?

The tabulation below lists some of the possible methods.

WATER SIDE PROBLEMS

PROBLEM ACTION METHOD

Hardness Soften Base Exchange

Acidity/pH Dose Phosphates & caustic soda

Oxygen Scavenge Sodium Sulphite or Hydrazine

TDS Reduce Blow down or De-alkaliseor De-mineralise

Turbidity Remove Filter

Organic Prevent Boil out

Silica(Not very critical Reduce De-mineraliseIn low pressure boilers)

Hardness removal by softening

While there are methods like lime/soda treatment or treatment with some proprietary chemicals themost popular and perhaps the best method to be adopted for softening is the base exchange processusing ion exchange resins. For this purpose filtered water is passed through an ion exchange resinbed. The type of resin used is usually a strong acid cation exchange resin in sodium form. It isspecifically efficient for removing strong metallic ions like calcium and magnesium from the waterwhich impart hardness. When the water passes through the bed, calcium and magnesium ions areexchanged by the resin with sodium ions. Sodium salts do not impart hardness to water and thus thewater is effectively softened. The exchange process can continue until the sodium content in theresin is depleted. The resin at this time can be regenerated to its original strength by using asolution of sodium chloride (common salt) of appropriate concentration. The details of the processand operational parameters are available in the instruction manual of the water softener.

De-alkalisation It is sometimes not sufficient to remove hardness from the water due to a high concentration of totaldissolved solids in the raw water. If a large portion of this TDS is due to bicarbonates it is possibleto reduce the TDS by a method called de-alkalisation. For this purpose the water is first passedthrough a bed of a weak acid cation resin in the hydrogen form. When the water passes through thisbed the metallic ions associated with bicarbonates are exchanged with hydrogen ions. Thus insteadof bicarbonate salts the water would now contain carbonic acid which is nothing but dissolvedcarbon dioxide. This water containing dissolved carbon dioxide is then passed through a degassertower and air is blown through the water using a blower. The air current drives away carbondioxide from the water thus effectively removing the bicarbonate salts reducing the TDS. This wateris then passed through the strong acid cation exchange resin in the sodium form as usual to removethe hardness. For detailed operating parameters appropriate instruction manuals are to be referredto.The de-alkaliser resins are regenerated usually using hydrochloric acid (Hydrogen chloride) so that

the regenerated resin comes back to hydrogen form.

Demineralisation

When water contains a large amount of TDS which cannot be treated by de-alkalisation or whenprocess requirement is for very low TDS, demineralisation needs to be resorted to. The raw waterafter filteration is first passed through a strong acid cation exchange resin bed in the hydrogen form.When the raw water passes through this bed the metallic ions are exchanged with hydrogen ions-This water containing now the corresponding acids instead of metallic salts is passed through astrong base anion resin bed where the acid radicals are replaced by hydroxyl ions- Thus resin bed inthe acid content "ets converted to water. The entire TDS is hence removed.

The cation resin is regenerated using hydrochloric acid to supply the hydrogen ions for exchangeand the anion resin is regenerated using sodium hydroxide to supply the hydroxyl ions for exchange.Depending on the raw water impurity levels and types, various combination of exchange beds anddegassers can be arranged to obtain control over impurities.

Reverse Osmosis

ADVANTAGES OF A REVERSE OSMOSIS SYSTEM OVER DM

We would like to propose an RO based treatment scheme in place of DM based system. We would like to highlight that the R.O. based treatment system shall be more beneficial in terms of following parameters :

1. Very less operating cost. (Enclosed an annexure on typical operating cost calculations for DM & RO)

2. Less chemical handling and storage.3. Very less operational needs thus the manual Reverse Osmosis Plant shall suffice in place of an automatic DM Plant.

4. Less civil work.5. Less area requirements.6. Reverse Osmosis system can take the marginal variations in feed water quality without

affecting the treated water parameters.7. No need for any neutralisation pit. The RO reject & MB regeneration effluents can be

directly taken to guard pond.

Dosing

To obtain the necessary quality of feed water and boiler water it is not sufficient to just removeimpurities. It is necessary to conditions the water by adding necessary chemicals. The addition of

necessary chemicals in the appropriate quantity is called dosing.

Phosphates

Various phosphate salts of sodium are used for dosing the feed water. Perhaps the most commonsalt is trisodium phosphate. The advantage of using this salt is its ability to hold residual hardnessslipped out of the ion exchange column as a sludge within the boiler thus effectively preventingadhering scales. Use of sodium hexameta phosphate is preferred by some as this chemical chelatesthe calcium salts and holds the hardness in solution without allowing these to precipitate. Sodiumhexametaphosphate is however more expensive. The phosphate salts increases alkalinity andincrease the pH value. The quantity of the phosphates is to be determined taking into considerationthe ratio of caustic alkalinity to total alkalinity needed as well as the minimum quantity required tohold hardness without scaling-

Caustic Soda

To maintain the necessary pH in feed water and boiler water it may be necessary to add caustic sodain addition to phosphate salts. The quantity of the caustic soda to be used will depend upon the ratioof the caustic alkalinity to total alkalinity required and the minimum quantity needed to maintain thespecified pH.

Sodium sulphite

Oxygen scavenging is an essential requirement for boiler water conditioning- Either sodiumsulphite or hydrazina can be used. Hydrazine reacts with oxygen in water forming ammonia andwater. Ammonia being a gas is removed from the water. Thus even though it may appear thathydrazine is better for scavenging oxygen (except for high pressure boiler) sodium sulphite isalways preferred, as hydrazine is toxic during handling. Sodium sulphite combine with oxygenforming sodium sulphate, effectively removing oxygen from the water. One important aspect ofdosing sodium sulphite which is always to be borne in mind is the reaction time required forconversion of the sulphite to sulphate. A minimum of 30 minutes of residence lime is required forthis reaction. Therefore, the dosing of the sodium sulphite is necessary to be arranged in such awaythat this residence time is available for the feed water before it enters the boiler. A catalysed varietyof sodium sulphite is available which does not require long residence time for the reaction.However, due to the much higher cost of the catalyst generally it is much cheaper to provide theresidence time. it is also necessary to keep in mind that the sulphite treated water should not beexposed to air before feeding into the boiler as otherwise oxygen from the air can continuouslydissolve and react with the sulphite available thus depleting the sulphite content in the feed water-The quantity of the dissolved oxygen depends on the temperature of water. At 30°C approx. 7.5mg/1 can he expected in the water. At about 100°C the oxygen content at atmospheric pressure is negligible.

The quantity of the sulphite to be dosed is to be determined according to the expected level ofdissolved oxygen in the feed water and the required residual sulphite content in the boiler water. 9mg Sulphite is required to remove one mg oxygen.

Proprietory feed water conditioning chemicals

There are many proprietory formulations for feed water conditioning combining the effects ofvarious chemicals explained above. Some of these formulations contain components like ethylenediamine tetra-acetic acid (EDTA) and such other chelating agents which may enhance theeffectiveness of conditioning- While choosing such formulations it is also necessary to bear in mindthat sometimes some of the components used in such formulation may be deterimental for use in aboiler in particular situations. It is necessary to know the exact nature of the components in theseformulations and their effects before deciding the use. The Thermax service engineers will he in aposition to give assistance in this regard.

Blowdown

It will he seen that inspite of all treatment boiler water will contain dissolved solids. In order tokeep the level of total dissolved solids in shell type and writer tube-drum type boilers within limits and to remove any sludge, loose scales and corrosion products a certain quantity of boiler is to beregularly drained. This process is known as blowdown. The blow down can be intermittent - sayonce a shift - or continuous. The quantity of the water to be blown down will depend on thedissolved solids entering the boiler through the feed water and the maximum tolerable levels ofthese salts in the boiler water. While determining the dissolved solids content in the feed water it isnecessary to take into account not only the original dissolved solids but also the dissolved solidsadded in the form of dosing.

Continuous blowdown

Continuous blowdown is a continuous removal of boiler water controlled by a specially designedadjustable valve or by an orifice plate. The installation of heat recovery equipment may beeconomically Justified. Suspended solids may block or erode the adjustable valve or orifice plateand continuous blowdown is therefore usually limited to the control of dissolved solids. Additionalmanual blowdown is necessary to control suspended solids and prevent the build-up of sludge.

Intermittent blowdown

Intermittent blowdown may be effected by specially designed valves either operated by hand orautomatically controlled, for example, by timers, feed water flow or conductivity. Where automaticvalves are installed the manual blowdown valve should be operated at intervals to ensure that thelatter is clear. It should be noted that the most effective and economic use of all types ofintermittent blowdown valves is achieved by frequent full-open operation for short periods ratherthan extended use at infrequent intervals. It is usually not practicable to recover waste heat frominfrequent intermittent blowdown.

Calculation of blowdown

The formulae in this subclause may be used to estimate the minimum quantity of water that shouldbe removed from a boiler during blowdown as shown in figure, where

E is the evaporation rate (in 1000 kg/h*)

S is the impurity content of feed water (in g/m3)

V is the water content of boiler (in m3)

C is the maximum permitted concentration of impurity in boiler water (in g/m3)

Cl is the concentration of impurity in boiler water on completion of intermittent blowdown (in g/m3)

B is the actual intermittent or continuous blowdown rate as percentage of evaporation rate.

BA is the average (intermittent) blowdown rate as percentage of evaporation rate.

d is the duration of intermittent blowdown operation (in hours)

t is the interval between completion of one blowdown operation and completion of the next (in h)

These formulae are based on steady load conditions and on the assumption that priming andcarryover conditions are absent or negligible. It is also assumed that the feed water treatment issuch that alt the dissolved solids in the feed water remain in solution in the boiler and do notprecipitate as scale or sludge. They may be applied only when the solids content of the feed wateris reasonably constant and is measurable by conventional means.

NOTE 1

When calculating blowdown on the basis of dissolved solids it is essential to make allowance forthe effect of the addition of treatment chemicals to the water.

NOTE 2

The amount of water required to be removed by intermittent blowdown is greater than thatnecessary when continuous blowdown is used (see fig.)

NOTE 3

When considering new water treatment plant, or alternative feed waters, the blowdown requiredshould not exceed the allowance made for it in the boiler plant design.

Blow Down — Controlling factor :

The blowdown quantity required is determined by the proportion of various impurities in thefeedwater. For a certain composition of feedwater, blowdown has to be calculated for all theimpurities. The maximum of these valves should be the actual blowdown.

Example - 1

Feedwater has a TDS of 600 mg/1, total alkalinity of 80 mg/1 and silica level of 20 mg/1.

a. Blow down required to limit the TDS :

S=600C = 10000 (From experience say, of a coil boiler)

600Hence B = 100 ——————————— = 6.4%

10000-600

b. Blowdown required to limit total alkalinity :S=80C = 700 (as per IS 10392)

80Hence B = 100 x ——————— = 12.9%

700 - 80

c. Blowdown required to limit silica :

S=20C = 140 (as per IS 10392)

20Hence B = 100 x ——————— = 16.7%

140-20

Thus total silica in the boiler water will determine the blowdown quantity in this case, andblowdown required will be 16.7%.

However, if it is desired that TDS should not exceed 3500 mg/1, (say as is required for a water tubeboiler), then

S = 600 C = 3500

600Hence B = 100 x ——————————— = 20.7%

3500-600

Thus TDS in boiler water will determine the blowdown quantity now, and blowdown required willbe 20.7%.

CHEMICALS FOR CONSISTENT PERFORMANCE

After a prolonged running of the boiler or heater, heating surface fouling takes place due to sootdeposition on the tiue gas side and scale formation on the water or heat carrier side. Theperformance of the equipment can get severely affected if the heating surface is not cleaned.Chemicals are available to remove scales as well as to prevent scale formation. ChemicalDivision of Thermax Limited is in the business of manufacturing these chemicals.

Chemicals manufactured by Thermax Limited are basically of four types:

1. Boiler Water Treatment chemicals

2. Fuel additives

3. Fireside chemicals

4. Descaling chemicals.

Application of each type is i\s given below;

F.I BOILER WATER TREATMENT CHEMICALS

Untreated boiler water contains several impurities such as lower solubility salts, dissolved gasesand suspended paniculate matter. These result in seal ing and corrosion of boiler heating surface.Also formation of foam in the boiler drum and water carry over is not uncommon. To counterthese Thermax has 'Miixtreat' range of chemicals.

Product Application Function Remark

Maxtreat 3220 Coil type Boilers Corrosion inhibitor LiquidAntiscalantOxygen Scavanging

Maxtreat 3220S Coil type Boilers Corrosion inhibitor SolidAntiscalantOxygen Scavanging

Maxtreat 3221 Smoke Tube Boilers Corrosion inhibitor LiquidAntiscalantSludge Conditioning

Maxtreat 3222 Water Tube Boilers Corrosion inhibitor LiquidAntiscalantSludge Conditioning

Product Application Function Remark

Maxtreat 3223 Smoke Tube Boiler Corrosion inhibitor Liquidusing hard water Antiscalant

Sludge Conditioning

Maxtreat 3100 Smoke tube & Catalysed Oxygen PowderWater Tube Boilers scavenger Catalysed

sulphite base

Maxtreat 3200 Smoke Tube & Catalysed Oxygen LiquidWater Tube Boilers scavenger Catalysed Hydrazine

Base. No additionTo TDS

Maxtreat 3001 All Boilers Sludge conditioner Synthetic Ploymerkeeps precipitated Facilitates sludge salts in suspension. Removal through

blowdown.

Maxtreat 3002 All Boilers On line descalant EliminatesIron, Calcium and shutdown.Magnesium scaleremover

Maxtreat 3003 Shell/Drum Boilers Anti foam compound Reduces carryoverDue to foaming.

Maxtreat 3004 All boilers Increases alkalinity Liquidin boiler feedwater

Maxtreat 3005 All Boilers Reduces alkalinity Reduces blowdownfrequency

F.2 FUEL ADDITIVES

To improve rue! combustion, to minimise harmful side effects like corrosion, soot formation, fuelneeds proper treatment. Thermax offers a complete range of fuel treatment products such ;issludge (Jispers.int, w.iier emulsitier, pour point depressant, oil based surf.ictant, viscosityimprover, corrosion inhibitor etc. They improve combustion and he;it transfer for belterequipment utilisation ;ind increase life of the boiler.

Product Application Function

Thermosol Fuel oil treatment Prevents fuel polymerisation.Disperses sludge. Aids waterremoval & prevents corrosionof tanks/lines. Restrictsformation of waxy deposits.

Improves atomisation due toreduction in surface tension.Improves combustion andminimises S03 corrosion.

Thcrmomix Solid fuel treatment Binds dust & preventsspreading. Reduces unburntcarbon in ash. Reducesfouling & slag deposition-Increases ash fusiontemperature and reducesclinker formation.

F.3 FIRESIDE CHEMICALS

Sooting, clinker formation and oilier combustion deposits are common fireside occurrences inboiler and thermal fluid installation- Such deposits have to be cleaned manually by brushing,scouring or by chemical action- The adhesive properties of unburnt carbon results in the build-up of incombustible solids on the heat transfer surfaces. This carbon acts as a barrier to heattransfer resulting in higher stack temperature and lower healer efficiency.

Economix is a chemical formulation from Thermax for fireside cleaning of combustion deposits.It contains dispersants, chemicals and corrosion inhibitors. It can be directly fed into the furnacewhile the boiler is in operation. Economix gives complete removal of fireside deposits.

F.4 DESCALING CHEMICALS

Untreated water contains several impurities which deposit on the heating surface leading to poorboiler output and efficiency. It can, in extreme cases, even lead to the failure of the heatingsurface- Thermax has a range of descaling chemicals, which can effectively remove the scalesformed and make the surface clean. These chemicals are from 'Maxciean' range. Theapplication of each of these chemicals is ;is given below:

MAXCLEAN- 05

An offline descalant. It is sulphamic aicid based with a corrosion inhibitor.

MAXCLEAN-06

An off line descalant for removing organic deposits and silica scales. It is a balancedformulation of a caustic, wetting agent and a silica deposit penetrant.

MAXCLEAN- 07

An alkaline formulation designed for boil-out in the boilers. It removes organic foulants likegrease, oil etc. from the boilers and softens silica scales.

In addition to the chemicals mentioned above, Thermax also supplies Water Analysis Kit. Thistest can be used for quick and reliable checks of boiler feedwater /boiler water. Thermax offers'Q-TEST KIT' which can be used for carrying out following test at the site.

Tablets Q-Test-4(Portable water analysis kit)

Hardness 1. Hardness testM. Alkalinity 2. Sulphite testP. Alkalinity 3. P. Alkalinity testDissolved oxygen 4. M. Alkalinity testpH test 5. pH test

6. Total dissolve solids7. Chlorides8. Phosphates9. Silica

For your requirements of the chemicals and expert advice, please contact any of the branchoffices/service franchisees or Thermax dealers. They will be in a position to assess yourrequirements and arrange for the supply. Or you may directly contact:

Agni Engineers, Protherm EngineersIndore- 452 008 Bhopal-462026Phone: 2536621/5023065 Mob:9827025810Fax:(0731)2532868 TeleFax: (0755)2418055Email: agni_engg@mantrafreenet.corn Ernail:protherrn@sanchrnet.in

Unimod Systems, Thermax LimitedIndorc-452018 Indore -452 001Ph: 2546314/2545596 Mob:9826339863Fax:(0731)2534830 Ph: (0731)2529233Email : unimod@sancharnet.in Email: thermax@sancharnet.in