ships ships heat generation plantheat generation · pdf filepag |1 - 94 report: alvaro...

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REPORT: ALVARO SARDINHA

MARINE ENGINEER

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BOILERS WATER TREATMENT

DATE: 2014.07.14

SHIPS SHIPS SHIPS SHIPS HEAT GENERATION PLANTHEAT GENERATION PLANTHEAT GENERATION PLANTHEAT GENERATION PLANT

Boilers Water TreatmentBoilers Water TreatmentBoilers Water TreatmentBoilers Water Treatment

2014.07.14

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INDEXINDEXINDEXINDEX

1. Introduction1. Introduction1. Introduction1. Introduction

2. Boiler2. Boiler2. Boiler2. Boilerssss water treatment water treatment water treatment water treatment –––– three factorsthree factorsthree factorsthree factors

3. Boilers 3. Boilers 3. Boilers 3. Boilers water water water water fundamentalfundamentalfundamentalfundamental knowledgeknowledgeknowledgeknowledge

4444. . . . ShipsShipsShipsShips heat generation plantheat generation plantheat generation plantheat generation plant

5555. . . . BoilerBoilerBoilerBoilers water treatments water treatments water treatments water treatment

6666. Main problems in boilers caused by water. Main problems in boilers caused by water. Main problems in boilers caused by water. Main problems in boilers caused by water

7777. Unex boiler. Unex boiler. Unex boiler. Unex boilerssss water water water water recommendationsrecommendationsrecommendationsrecommendations

8888. Lessons learned. Lessons learned. Lessons learned. Lessons learned

9999. Water chemistry terms. Water chemistry terms. Water chemistry terms. Water chemistry terms

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1. INTRODUCTION1. INTRODUCTION1. INTRODUCTION1. INTRODUCTION

If boilers water doesn’t receive proper treatment, the boiler will suffer from

carryover, sludging, scale and corrosion, leading to weak and dangerous

machinery.

Long before the boiler fails, water-related problems will cause:

● Growing safety hazard

● Increased maintenance cost

● Additional fuel required - higher energy costs

● Lower boiler efficiency

Correct boiler water treatment and follow-up of the water and steam condition,

are of utmost importance for keeping the heat generation systems in good

condition.

By implementing a rigorous program of boiler water treatment, a vessel can

greatly extend equipment life, reduce maintenance and enable thermal efficiency

to be maintained at the designed level.

The present report characterizes a ship heat generation system, its water

treatment procedures and maintenance required. The main objective is to

document the system and to establish optimal and standard operation processes.

It is also an important piece of digital information, part of the ship information

system, shareable and available for present and future crews, and a helpful tool to

support company management.

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2. BOILER2. BOILER2. BOILER2. BOILERSSSS WATER TREATMENT WATER TREATMENT WATER TREATMENT WATER TREATMENT ---- THREE FACTORSTHREE FACTORSTHREE FACTORSTHREE FACTORS

1. CHEMICAL TREATMENT

Water normally contains various levels of contaminants, dissolved solids

(minerals) and dissolved gases. These contaminants cause major operational

problems and damage to boilers unless they are removed or controlled on a

continuing basis. Correct application of chemical treatment programs can

eliminate many problems associated with boiler operations.

But other problems can and do impact operations.

They are into two major areas:

Management concerns - Addresses the administration of boiler water operations.

Operator performance - Addresses the hands-on operation of boilers.

2. MANAGEMENT CONCERNS

Every installation has its own mode of operation and style of management.

Boiler water treatment is one small area of operations but is so critical that

complete base operations may cease if boilers are not operated properly.

Observations indicate that major difficulties found in boiler water treatment

systems can be traced to management actions.

3. OPERATORS PERFORMANCE

The successful operation of boilers requires accurate analysis of the water that is

used, proper treatment to remove corrosive minerals and gases, and careful

attention to the controls and procedures for the taking of water samples, their

testing, and all required inspections.

The key players are the boiler operators and, of course, assigned supervisors.

A basic knowledge of boiler mechanics and water chemistry is an absolute

requirement, whether through formal training or on the job training.

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3. BOILER3. BOILER3. BOILER3. BOILERSSSS WATER FUNDAMENTAL KNOWLEDGEWATER FUNDAMENTAL KNOWLEDGEWATER FUNDAMENTAL KNOWLEDGEWATER FUNDAMENTAL KNOWLEDGE

A boiler is a device for generating steam, which consists of two principal parts: the

furnace, which provides heat, usually by burning a fuel, and the boiler proper, a

device in which the heat changes water into steam. The steam is then recirculated

out of the boiler for use in various processes in heating applications.

There are basically two types of boilers:

A. WATER TUBE (20% of boilers in use)

Water is fed through a bundle of tubes inside the boiler, and heat is applied to the

outside of the tubes to heat the water.

B. FIRE TUBE (80% of boilers in use)

Heat travels through a bundle of tubes inside the boiler to heat the water

surrounding the tubes.

The bundle of tubes which carries water in the Water Tube Boiler and heat in the

Fire Tube Boiler is called the Heat Transfer Surface.

Both the Water Tube and the Fire Tube Boiler have the following components:

HEAT SOURCE - A gas, oil, or coal burner heats the water in the oiler.

HOTWELL - Tank that receives make-up water from ship water tanks and steam

condensate from the condenser, feeding the boiler with water. The hotwell is

heated to drive off dissolved oxygen and carbon dioxide gases before the water

enters the boiler. Since these gases dissolve more readily in cold water, heating

helps to eliminate them. Dissolved gases cause corrosion in the boiler. Scale and

corrosion prevention chemicals are added at the hotwell to condition the water

before it enters the boiler.

CONDENSER – Equipment where steam return from consumers and is condensed

by lowering its temperature, through sea water circulation and heat transfer.

FEED WATER - The water entering the boiler from the hotwell.

Feedwater = Make-up Water + Condensate Return

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MAKE-UP WATER - The fresh water entering the hotwell from ship water tanks, to

compensate steam losses and blow-down. It could be raw water received from

shore or distilled water produced on ship.

Make-up Water = Blow-Down + Condensate Loss

FEED WATER PUMP - When heated water from the boiler is given off as steam,

and the pump feeds water into the boiler from the hotwell. The feed water pump

must generate sufficient pressure to overcome the pressure in the boiler.

BLOW-DOWN VALVE - This valve allows some of the water carrying accumulated

solids ("sludge") in the boiler to drain off. The act of removing water and sludge

from the boiler is called "blow-down."

WATER LEVEL CONTROL - The Water Level Control maintains the proper water

level inside the boiler. This water level can be visually checked at the sight glass.

The boiler tubes will become overheated if the water level is too low to keep the

heat transfer surface covered. Low water level will cause excessive stress to the

boiler. High water level will allow water to get into the steam lines, reducing the

efficiency of the boiler system.

SAFETY VALVES - These valves automatically releases any excess pressure that

builds up in the boiler. Every boiler has several safety mechanisms that will shut it

off in the event of malfunction.

The boiler receives the feed water, which consists of varying proportion of

recovered condensed water (return water) and fresh water, which has been

purified in varying degrees (make-up water).

The make-up water is usually distilled water or natural water, either in its raw

state, or treated by some process before use. Feedwater composition therefore

depends on the quality of the make-up water and the amount of condensate

returned to the boiler.

The steam, which escapes from the boiler, frequently contains liquid droplets and

gases. The water remaining in liquid form at the bottom of the boiler picks up all

the foreign matter from the water that was converted to steam. The impurities

must be blown down by the discharge of some of the water from the boiler to the

drains. The permissible percentage of blow-down is strictly limited by running

costs and initial outlay. The tendency is to reduce this percentage to a very small

figure.

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Proper treatment of boiler feed water is an important part of operating and

maintaining a boiler system.

As steam is produced, dissolved solids become concentrated and form deposits

inside the boiler. This leads to poor heat transfer and reduces the efficiency of the

boiler. Dissolved gasses such as oxygen and carbon dioxide will react with the

metals in the boiler system and lead to boiler corrosion.

In order to protect the boiler from these contaminants, they should be controlled

or removed, trough external or internal treatment.

Natural water can damage a boiler by producing:

1) Scale and

2) Corrosion

Water always contains some impurities in the form of dissolved solids and gases.

The solids are calcium, magnesium, and other salts that form scale; the dissolved

oxygen and carbon dioxide gases cause corrosion of metal.

DISTILLED WATER SHOULD BE USED AT ALL TIMES.

SCALE

As water flows over rock formations and through the earth, it picks up and

dissolves calcium and other metallic salts. When water enters a boiler, where it is

heated to produce steam, these dissolved solids precipitate out of solution. The

precipitates are left behind in the boiler water - they do not travel with the steam.

If they are allowed to accumulate, they will settle out as scale on the boiler metal.

This is what happens when water in a pan on the stove is allowed to boil dry, or

when water in a glass is allowed to evaporate completely. A residue of salts will be

left, which is scale.

When chemical treatment is not used, scale forms in a boiler. If scale is allowed to

build up, it reduces the heating efficiency of the boiler. A heavily scaled boiler

heats water to steam at a slower rate, because the scale acts as an insulator. This

increases operating costs.

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The amount of scale depends on the amount of dissolved solids in the water. If

water is added, the scale residue will not go back into solution. The U.S. Bureau of

Mines has determined that a thickness of only 2,82 mm scale in a boiler increases

fuel costs in 16%.

CORROSION

Gases in the air are soluble in water. The two that cause the most problems are

oxygen and carbon dioxide.

Dissolved oxygen in water entering the boiler causes corrosion, which will pit and

weaken the boiler. Rust is formed as a by-product. Rust deposits interfere with the

boiler's heating efficiency. This slower heating ability increases the boiler's

operating cost.

Carbon dioxide corrosion occurs in the condensate return system. Carbon dioxide

is released as a gas when water is converted to steam. This gas travels with the

steam. When steam liquefies and enters the condensate return lines, the carbon

dioxide gas is absorbed in the condensate water, forming a weak acid which will

eventually "groove" or wear away the metal.

TREATING THE WATER

Natural water is not pure. Rain water is contaminated by airborne dust particles.

Water passing through soil and over rocks picks up minerals. Even mountain

spring water derives its good taste from the minerals it contains. These same

minerals cause scale in boilers. Consequently, all boiler feed water requires

treatment.

Water contains various impurities in an infinite variety of combinations and

amounts. Water from different locations, then, will differ in the amount of

chemical treatment needed to prevent scaling and corrosion. Tests must be made

on the water at each location to determine how much treatment should be used.

The tests usually used are as follows:

HARDNESS TEST - Hardness is a word used to describe dissolved calcium and

magnesium salts in water. We can determine the amount of these salts in water

by simple titration; that is, adding chemical Hardness indicators to a sample of

water.

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Hardness is expressed in ppm, which stands for parts per million. Let's say the

result of the Hardness test is 20 ppm. This means that for every 1 million Kg of

water, there are 20 Kg of hardness salts (dissolved calcium and magnesium).

Hardness must be precipitated out of water so that scale does not form. When

high alkalinity is present in the water, hardness is precipitated as soft sludge that

is held in suspension until blow-down. When low alkalinity is present in the raw

water, the alkaline builders in added chemical products provide the alkalinity

necessary to precipitate the hardness as soft sludge. A smaller dosage of

chemicals will be used if the make-up water is highly alkaline.

ALKALINITY TEST - Sodium hydroxide provides a highly alkaline environment in the

boiler. This is about the only environment where water and steel get along well.

Heat magnifies the normally corrosive effect water has on steel, since it speeds up

chemical reactions. Maintaining the correct alkalinity range minimizes this highly

corrosive effect of water. Alkalinity also plays a critical part in various chemical

reactions in the boiler. Frequently, most of boiler water alkalinity comes from the

addition of sodium hydroxide in the chemical program. Some of the alkalinity

comes from naturally occurring alkalinity found in raw water supplies. If it is

present naturally, it contributes to the required alkalinity in the boiler and

decreases the amount of sodium hydroxide needed.

Alkalinity is typically measured as either P-Alkalinity (Phenylthalein Alkalinity),

M-Alkalinity (Methyl Orange Alkalinity), or OH-Alkalinity (Hydroxide Alkalinity).

P-Alkalinity is determined by a relatively simple titration procedure. OH-Alkalinity

is determined by either using a modified version of the P-Alkalinity test, or by

calculation using P and M-Alkalinity (2xP-M=OH). OH-Alkalinity is primarily the

most important. However, P-Alkalinity is more convenient to test. If P-Alkalinity is

in range, the OH-Alkalinity will be also. Boiler alkalinity is directly related to boiler

pH so if the alkalinities are in range, the pH will be also.

"M" ALKALINITY TEST - This is used to determine the Total Alkalinity of the raw

water in ppm. The result of the "M" Alkalinity test is used to determine how much

chemical products should be added to feedwater.

SULFITE TEST - This test indicates the amount of Sulfite in the water. Sulfite and

oxygen cannot coexist; therefore, by keeping an excess of sulfite in the boiler

water, we can be sure there is no oxygen is present. If no oxygen is present, no

acid can be formed and there will be no corrosion.

Sulfite is used to consume dissolved oxygen in steam boiler systems. If dissolved

oxygen is permitted to exist in the boiler, it attacks the steel in the boiler forming

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oxygen pits. This pitting causes serious damage and eventually tube failure. This is

the most common form of corrosive attack in steam boilers. Dissolved oxygen can

also flash-out with the steam and cause corrosion throughout the condensate

return system. Sulfite reacts with dissolved oxygen to form sulfate, thus making

the oxygen unavailable to damage system metals. Sulfite is best fed into the feed

water system as far upstream as possible. The optimum feed location is at the

storage portion of a deaerator. A long distance in the feed water stream increases

the reaction time of the sulfite with the oxygen decreasing the possibility of

oxygen getting into the boiler. Consequently, much of the feed water system also

gets protected.

PHOSPHATES TEST - Phosphates are used to react with calcium and magnesium

hardness to produce controllable materials removable by blow-down. Phosphates

should be added to low pressure boilers to maintain a residual of 30 to 60 ppm as

ortho-phosphate. Any calcium or magnesium present will consume the ortho-

phosphate. Hard make-up water requires enough phosphate to maintain the 30 to

60ppm residual in addition to that needed to neutralize all of the calcium and

magnesium hardness in the boiler water. Soft make-up water only requires

enough phosphate to maintain the same 30 to 60 ppm residual. A boiler on soft

make-up can be operated at higher cycles of concentration, thus requiring less

blow-down and less chemical treatment in general.

CONTROL TEST FOR ISOMINE - Phenolphthalein is an indicator which is colorless

below and pink above a pH of 8.2. When the pH of the condensate is higher than

8.2, pink indicates that corrosion is being prevented effectively. A red color

indicates excess chemical is being used; therefore, the feed rate should be

reduced.

CONDUCTIVITY TEST - Conductivity testing is used to monitor the amount of

material dissolved in water by measuring its ability to conduct electricity. The

more material dissolved in the water, the higher its conductivity will be. As a

boiler approaches its maximum allowable cycles, it will also approach its maximum

allowable conductivity. If boiler water's conductivity gets too high, indicating

excessive dissolved material is present, steam will start to have trouble escaping

the water's surface. This phenomenon is due to increased water surface tension

from higher dissolved solids concentrations. The boiler at this point will begin to

prime, or foam and bounce, resulting in tiny droplets of boiler water carrying over

with the steam. Good quality steam is essentially distilled water. Carryover

reduces the BTU content of the steam resulting in excess fuel consumption and

reduced efficiency.

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CHLORIDE TEST - When water is converted to steam, the dissolved solids do not

travel with the steam, but are left behind in the boiler water. Water enters the

boiler to replace the amount lost through steam evaporation. When this new

water is converted to steam, more solids are left behind. As steam is continually

produced, evaporated, and replaced with new water, the amount of solids in the

boiler continues to increase.

For every Kg of steam generated, a Kg of water must be replaced. The amount of

solids in the water will have doubled when the amount of new water that has

entered the boiler is equal to the amount of water that was used to originally fill

the boiler. When the amount of solids has doubled, there are 2 cycles of

concentration in the water; when the amount of solids has tripled, there are 3

cycles of concentration. Cycles of concentration is an indicator of the amount of

solids build-up in the water.

Chloride is chosen as the indicator for cycles of concentration because, 1) it is

always present in the make-up water, 2) it does not change character when

heated, 3) it is not affected by chemical treatment, and 4) like the other dissolved

solids, it does not leave the water in the boiler when steam is produced.

If the Chloride in the water doubles, all the solids have doubled. Elevated levels of

chlorides (over 200 ppm) in the water of steam boilers will accelerate water side

corrosion and shorten the operating life of the boiler.

DISPERSANTS - Phosphate precipitates (sludge) must be dispersed thoroughly to

prevent them from baking on to the heat transfer surfaces of boilers. A variety of

dispersants are used for this purpose and must be fed in a proper ratio to the

phosphate treatment.

AMINES - Return condensate is naturally corrosive because of its purity. The pH of

pure water is easily decreased in the presence of carbon dioxide. Carbon dioxide

dissolves in the water to form carbonic acid. Oxygen readily dissolves in pure

water also. Both low pH and dissolved oxygen lead to corrosion in any water

system especially in the presence of heat. The amount of carbon dioxide depends

primarily on the amount of carbonates present in the make-up water. Various

amines are used to neutralize the resulting carbonic acid in condensate causing

the pH to stabilize at higher less corrosive levels. The return condensate system is

then protected from carbonic acid corrosion.

Reducing corrosion decreases the amount of corrosion products that would

normally return to boiler and form deposits. These deposits can be the most

difficult to remove.

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Neutralizing amines should be fed at a rate sufficient to produce a return

condensate pH of 8 to 9 for best results. The exact feed rate depends on the

percent of condensate return since higher return rates mean less make-up, the

primary source of carbon dioxide. A higher return rate also means better recycling

of the amine already fed into the system. As a result, less amine has to be fed to

replace what is lost. Amines may be fed in several locations depending on the

configuration of the system. They may be fed directly into the boiler, the steam

header, or into various strategic steam line locations.

Some recycled amine will be lost in a deaerator since some steam is vented from

it. Adding the amine to the steam header downstream of steam line to the

deaerator makes economical sense.

EFFICIENT AND EFFECTIVE BOILER CHEMISTRY

In order to fully understand what a given boiler needs for treatment, a basic study

of its supply water must be done first. Three types of impurities exist in all supplies

and can cause a wide range of problems in boilers. These impurities are

suspended solids, dissolved solids, and dissolved gasses.

Water picks up the impurities from the ground it contacts and the air through

which it falls. The type of impurity depends on contact time, and stream velocity.

The amount of rainfall and where the rain occurs on the watershed can and does

result in changes in the character of the water throughout the year. Water

supplies typically come from one of two sources, ground water or surface water.

Generally, ground water contains more dissolved solids and less suspended solids

and dissolved gases. Generally, surface water contains more suspended solids and

dissolved gases and less dissolved solids.

Most problems due to impurities present in the water can be solved chemically,

one way or another. It is usually most economical, however, to address the

impurities by physical or mechanical means, using chemical treatment only to

clean up the remaining traces left after physical treatment.

Boiler operators have control over two basic aspects of the chemical program:

blow-down and chemical feed. Blow-down requirements are determined by the

type and amount of impurities that exist in the make-up water. Blow-down rates

of course directly affect chemical feed rates. Therefore, a complete analysis of the

raw and make-up water is the first step in establishing the correct program.

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Specifically, there are a number of advantages to a properly managed boiler

chemistry program. Boiler chemistry programs include not only chemical addition,

but also pre-treatment equipment. Maximized equipment life, reduced

maintenance costs, minimized down time, maximized safety, optimized chemical

costs, minimized fuel costs, minimized water consumption, and minimized waste

water are the main benefits.

Equipment that is properly protected will last longest and will require the least

amount of maintenance and down time. The same equipment is less likely to have

catastrophic failures leading to safety concerns. Properly treated systems will also

reduce chemical, fuel, and water consumption to a minimum. Reduced water

consumption directly translates into further reduced fuel consumption since every

Kg of water that enters the system requires energy to raise its temperature to turn

it to steam.

Chemical feed

Chemical feed is best done in proportion with water use. Like blow-down control,

make-up or feed water flow rates can be used to actuate chemical feed systems.

This chemical feed technique automatically compensates for changes in steam

load, giving stable chemical treatment control in the system.

One of the simplest ways to employ this technique is to have the feed water

pumps actuate the chemical pump(s). Once blow-down and chemical feed rates

are correct and stable, testing should be done regularly to monitor any changes

that may occur in the system. Any chemistry changes may be indicators of

mechanical changes in the system. Once the relationship of boiler chemistry is

fully understood, an attentive operator can diagnose problems to his plant by

noticing changes to boiler chemistry.

Understanding Boiler Treatment Control Ranges

Many factors, such as the system design, operating conditions, make-up water

quality, chemical feed and control equipment, on-site monitoring program, and

treatment chemicals, are considered when specifying the control ranges for a

boiler treatment program.

Operation outside of these control parameters can result in problems that

increase operation and maintenance costs, damage the boiler system, and result

in system failure.

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Below are presented descriptions of some common boiler treatment control

ranges and their importance to the water treatment program.

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4444. SHIP. SHIP. SHIP. SHIP HEAT GENERATION PLANTHEAT GENERATION PLANTHEAT GENERATION PLANTHEAT GENERATION PLANT

The heat generating plant in a ship, may include oil-fired steam boilers with fire-

tubes (auxiliary boiler) and exhaust gas boilers with water tubes.

EXAMPLE OF AN OIL-FIRED BOILER

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EXAMPLE OF AN EXHAUST GAS BOILER

An exhaust gas boiler with water tubes has internal piping with forced water circulation.

Hot and partly evaporated circulating water is led from the outlet side of exhaust gas

boiler to the upper part of the water space at a oil-fired steam boiler, where steam gets

separated. Circulation pump will then pump the water back to the exhaust gas boiler,

from the lower part of the water space at a oil-fired steam boiler.

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CONDENSATE SYSTEM

The heat generation plant includes a condensator. It is circulated by sea water to cool and

condensate steam returning from several consumers. The condensates return then to the

water feed tank (hotwell).

May also be available one observation tank that receives the return steam, used to heat

fuel for main engines, diesel generators and oil-fired boilers, and steam used to heat the

fuel oil and lubricating oil, at purifier’s plant. At this tank is possible to check if there is oil

or fuel contamination of steam.

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5555. . . . BOILERBOILERBOILERBOILERSSSS WATER TREATMENTWATER TREATMENTWATER TREATMENTWATER TREATMENT

Correct use and careful maintenance of the boiler, increase its service life.

Maintenance of the burner and careful cleaning of the boiler are the most

important prerequisites for faultless operation. Also important for safety, working

life and security of boiler, are the correct treatment and maintenance of boiler’s

water.

The quality of water and functioning of the treatment equipment must be

regularly observed and any potential defects must be immediately eliminated.

A book of water values and functioning of devices must also be kept. In case of

potential malfunctioning, conclusions on reasons for them can be drawn on this

basis.

Characteristics of boiler feed water

Water absorbs more heat for a given temperature rise than any other common

inorganic substance. It expands 1600 times as it evaporates to form steam at

atmospheric pressure. The steam is capable of carrying large quantities of heat.

These unique properties of water make it an ideal raw material for heating and

power generating processes.

All natural waters contain varying amounts of dissolved and suspended matter

and dissolved gases. Since water impurities cause boiler problems, careful

consideration must be given to the quality of the water used for generating steam.

The composition of boiler feed water must be such that the impurities in it can be

concentrated a reasonable number of times inside the boiler, without exceeding

the tolerance limits of the particular boiler design. If the feed water does not meet

these requirements it must be pre-treated to remove impurities. The impurities

need not be completely removed in all cases, however, since chemical treatment

inside the boiler can effectively and economically counteract them.

Feedwater purity is a matter both of quantity of impurities and nature of

impurities: some impurities such as hardness, iron and silica are of more concern,

for example, than sodium salts. The purity requirements for any feedwater

depend on how much feedwater is used as well as what the particular boiler

design (pressure, heat transfer rate, etc.) can tolerate. Feedwater purity

requirements therefore can vary widely. A low-pressure fire-tube boiler can

usually tolerate high feed-water hardness with proper treatment while virtually all

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impurities must be removed from water used in some modern, high-pressure

boilers.

Only relatively wide ranges can be given as to maximum levels of alkalis, salt,

silica, phosphates etc, in relation to working pressure. The actual maximum levels

must be obtained from the boiler manufacturer, who will base them on the

characteristics of the boiler in question.

The need for control

Whether distilled or raw (city) water is used for boiler make-up, chemical

treatment is necessary to counteract harmful substances which are present.

Particularly, the contaminants present in raw water are inorganic sodium

compounds of chloride, sulfate and carbonate and the hardness (calcium and

magnesium) compounds of these same materials. Gases such as oxygen and

carbon dioxide are present in feed water, distilled or row water. Marine

evaporators do not remove all of the salts and minerals from seawater.

Minute particles are carried over from the evaporator in the water vapour and are

present in the distillate. Any leaks in the distiller, condensers or any part of the

feed system which is sea water cooled will add solids and further magnify the

existing problems.

Common impurities found in water

CALCIUM CARBONATE (CaCO3)

Calcium carbonate precipitates from calcium bicarbonate, a much more soluble

form, at the boiling point of water. But as calcium carbonate it has a measurable

solubility in water of approximately 19 ppm. This low solubility is sufficient to

cause it to form scale; the insoluble precipitate is in equilibrium with that which is

in solution, some therefore dissolving, while some comes out of solution. In so

crystallizing, it cements other free particles of matter not otherwise scale forming,

including precipitated calcium carbonate.

CALCIUM SULFATE (CaSO4)

Calcium sulfate precipitates forming a hard scale if the solubility at a given

temperature is exceeded. For example, at 40oC the solubility is 1551 ppm; at

100oC the solubility is 1246 ppm; and 40 ppm at 220

oC. Calcium sulfate has inverse

solubility (becomes less soluble as the temperature increases) causing deposition

problems. This negative solubility characteristic makes it more prone to crystallize

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where the heat is greatest; principally in the fire box where the highest heat

concentration occurs. Normal acids have no effect in dissolving this scale.

MAGNESIUM SULFATE (MgSO4)

Magnesium sulfate is one of the most soluble of salts, having a solubility of 20% in

cold water and 42% in boiling water. It exists only in water of low pH.

COPPER

Copper is introduced into the system by corrosion of copper piping and copper

alloys. In cooling systems this may be caused by excessive use of water treatment,

causing highly alkaline conditions. In boilers, the source of this corrosion is

excessive use of hydrazine, or leaking internal de-super-heater elements in boiler

drums, which allow alkaline boiler water to enter the de-super-heater steam

system and corrode copper and copper alloys, bringing the copper to the boiler.

Copper in the boiler displaces tube steel or “plates out”. This condition frequently

takes place under scale or sludge deposits and is often described as “under

deposit corrosion”.

SILICA (Si02)

Silica is not generally found in marine boilers except in minute quantities. Silica

will produce a very hard scale and may be admitted to systems only if severe

carryover has occurred from evaporators distilling water from rivers where the

silica content is high, or if feed water is taken from cement washed tanks. In

certain cases, when row water is evaporated and is high in silica, carryover may

admit silica into the distilled water system.

On some new vessels where silicate coatings have been used in distilled water

storage tanks, initial silica readings may be high and should be tested often and

controlled by blow-down. Silica may cause difficulty in cooling water systems by

forming calcium and magnesium silicate scale.

IRON OXIDES (FeO - Fe2O3 - Fe3O4)

Iron may enter the boiler as a result of corrosion in the pre-boiler sections or parts

of the feed system, or may redeposit as a result of corrosion in the boiler itself.

Often, iron oxide will deposit and retard heat transfer within a boiler tube,

sometimes resulting in tube failure. When iron is not present in the row water

feed, its presence in the boiler or cooling system indicates active corrosion, a

more serious problem than its presence in scale in which it appears by occlusion.

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Rust, the reddish form, is fully oxidized. More often, in a boiler with limited

oxygen, it is in the reduced or black form (Fe3O4). Fe3O4 is magnetic and can be

readily detected with a magnet.

OIL

To prevent oil from entering condensate and feedwater systems, certain safety

equipment is generally incorporated to remove or arrest such contamination if

this should arise. There are certain occasions due to mechanical failure (for

example, faulty oil deflectors at turbine glands passing lube oil to gland seal

condensers and main condensers, etc., or leaks at tank heating coils) causing oil to

enter a boiler.

Any oil film on internal heating surfaces is dangerous, impairing heat transfer

drastically to the extent that comparable heat retarding effects can be likened to

considerable dense scale build-up. Oil films therefore cause overheating of tube

metal, resulting in tube blistering and failure, or cracking of engine parts. If oil

contamination is suspected, immediate action must be undertaken for its removal.

DISSOLVED GASES

Dissolved gases are present in distilled water in the form of oxygen and carbon

dioxide. Each enters the condensate system from leaks in the vacuum side or open

exposure to the atmosphere, the atmospheric drain tank, surge tank, or feed filter

tank. Due to chemical reactions in water, carbon dioxide can form carbonic acid

(H2CO3), lowering the pH of the condensate, making it corrosive.

Oxygen is highly corrosive causing localized pitting and attack of boiler metal.

Mechanical deaerating equipment, if installed, is designed to remove the

majority of these dissolved gases. However, the most efficient deaerating

equipment still passes about 5 ppb (parts per billion) of dissolved gases. Chemical

treatment is required to render these gases harmless.

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ACIDITY, NEUTRALITY AND ALKALINITY

All water can be classified into one of these categories. Acidity, Neutrality and

Alkalinity are, however, only very general terms, and to know the degree of each

condition we require accurate methods of monitoring. The accepted terminology

denoting the exact characteristics we desire is pH.

pH is a numerical designation between 0 and 14 with 7 (the midway point) being

neutral. Any value down from 7 to 0 is the acid range, and values from 7 up to 14

are in the alkaline range.

The terminology pH is the negative logarithm of the hydrogen ion concentration

to the base 10. Therefore, a hydrogen ion concentration of 10 is expressed as pH 7

(neutral), 10-1 pH 1 (acid), and 10-14 pH 14 (alkaline). It is therefore obvious that

the difference between each number is 10 times and the difference between pH 7

and pH 10 is actually 1000 times.

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In the following tables are presented lists of the common boiler feed water

contaminants, their effect and their possible treatment.

IMPURITY RESULTING IN GOT RID OF BY

SOLUBLE GASSES

Hydrogen sulphide (H2S) Water smells like rotten eggs: Tastes

bad, and is corrosive to most metals.

Aeration, Filtration, and Chlorination.

Comments: Found mainly in groundwater, and polluted streams.

Carbon Dioxide (CO2) Corrosive. Forms carbonic acid in

condensate.

Deaeration; Neutralization with

alkalis.

Comments: Filming, neutralizing amines used to prevent condensate line

corrosion.

Oxygen (O2) Corrosion and pitting of boiler tubes. Deaeration; Chemical treatment with

Sodium Sulfite or Hydrazine.

Comments: Pitting of boiler tubes, and turbine blades, failure of steam lines, and

fittings etc.


SUSPENDED SOLIDS

Sediment & Turbidity Sludge and scale carryover. Clarification and filtration.

Comments: Tolerance of approx. 5ppm max. for most applications, 10ppm for

potable water.

Organic Matter Carryover, foaming, deposits can clog

piping, and cause corrosion.

Clarification; Filtration; Chemical

treatment.

Comments: Found mostly in surface waters, caused by rotting vegetation, and

farm run offs. Organics break down to form organic acids. Results in low of

boiler feed-water pH, which then attacks boiler tubes. Suspended particles

collect on the surface of the water in the boiler and render difficult the liberation

of steam bubbles rising to that surface.

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DISSOLVED SOLIDS

Oil & Grease Foaming, deposits in boiler Coagulation & filtration

Comments: Enters boiler with condensate

Hardness, Calcium (Ca),

and Magnesium (Mg)

Scale deposits in boiler, inhibits heat

transfer, and thermal efficiency. In

severe cases can lead to boiler tube

burn thru, and failure.

Softening, plus internal treatment in

boiler.

Comments: Forms are bicarbonates, sulfates, chlorides, and nitrates, in that

order. Magnesium reacts with carbonates to form compounds of low solubility.

Sodium, alkalinity, NaOH,

NaHCO3, Na2CO3

Foaming, carbonates form carbonic

acid in steam, causes condensate

return line, and steam trap corrosion,

can cause embrittlement.

Deaeration of make-up water and

condensate return; Ion exchange;

Deionization; Acid treatment of make-

up water.

Comments: Sodium salts are found in most waters. They are very soluble, and

cannot be removed by chemical precipitation.

Sulfates (SO4) Hard scale if calcium is present Deionization

Comments: Tolerance limits are about 100-300ppm as CaCO3

Chlorides, (Cl) Priming, i.e. uneven delivery of steam

from the boiler, carryover of water in

steam lowering steam efficiency, can

deposit as salts on superheaters and

turbine blades. Foaming if present in

large amounts.

Deionization

Comments: Priming, or the passage of steam from a boiler in "belches", is

caused by the concentration of sodium carbonate, sodium sulfate, or sodium

chloride in solution.

Iron (Fe) and Manganese

(Mn)

Deposits in boiler, in large amounts

can inhibit heat transfer.

Aeration; Filtration; Ion exchange.

Comments: Most common form is ferrous bicarbonate.

Silica (SiO2) Hard scale in boilers and cooling

systems. Turbine blade deposits.

Deionization; Lime soda process;

Hot-lime-zeolite treatment.

Comments: Silica combines with many elements to produce silicates. Silicates

form very tenacious deposits in boiler tubing. Very difficult to remove, often only

by flourodic acids. Most critical consideration is volatile carryover to turbine

components.

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Boiler water treatment

The treatment and conditioning of boiler feed water must satisfy three main

objectives:

• Continuous heat exchange

• Corrosion protection

• Production of high quality steam

External treatment

External treatment is the reduction or removal of impurities from water outside

the boiler. In general, external treatment is used when the amount of one or more

of the feedwater impurities is too high to be tolerated by the boiler system in

question. There are many types of external treatment (softening, evaporation,

deaeration, membrane contractors etc.) which can be used to tailor make

feedwater for a particular system.

The water treatment facilities purify and deaerate make-up water or feedwater.

Water is sometimes pre-treated by evaporation to produce relatively pure vapour,

which is then condensed and used for boiler feed purposes. Evaporators are of

several different types, the simplest being a tank of water through which steam

coils are passed to heat the water to the boiling point. Sometimes to increase the

efficiency the vapor from the first tank is passed through coils in a second tank of

water to produce additional heating and evaporation. Evaporators are suitable

where steam or other source of heat is readily available.

Certain natural and synthetic materials have the ability to remove mineral ions

from water in exchange for others. For example, in passing water through a simple

cation exchange softener all of calcium and magnesium ions are removed and

replaced with sodium ions. Since simple cation exchange does not reduce the total

solids of the water supply, it is sometimes used in conjunction with precipitation

type softening. One of the most common and efficient combination treatments is

the hot lime-zeolite process. This involves pre-treatment of the water with lime to

reduce hardness, alkalinity and in some cases silica, and subsequent treatment

with a cation exchange softener. This system of treatment accomplishes several

functions: softening, alkalinity and silica reduction, some oxygen reduction, and

removal of suspended matter and turbidity.

Chemical treatment of water inside the boiler is usually essential and

complements external treatment by taking care of any impurities entering the

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boiler with the feed water (hardness, oxygen, silica, etc.). In many cases external

treatment of the water supply is not necessary and the water can be treated only

by internal methods.

Internal treatment

Internal treatment is the conditioning of impurities within the boiler system. The

reactions occur either in the feed lines or in the boiler proper. Internal treatment

may be used alone or in conjunction with external treatment. Its purpose is to

properly react with feed water hardness, condition sludge, scavenge oxygen and

prevent boiler water foaming.

Internal treatment can constitute the unique treatment when boilers operate at

low or moderate pressure, when large amounts of condensed steam are used for

feed water, or when good quality raw water is available. The purpose of an

internal treatment is to:

1) React with any feedwater hardness and prevent it from precipitating on the

boiler metal as scale;

2) Condition any suspended matter such as hardness sludge or iron oxide in the

boiler and make it non-adherent to the boiler metal;

3) Provide anti-foam protection to allow a reasonable concentration of dissolved

and suspended solids in the boiler water without foam carryover;

4) Eliminate oxygen from the water and provide enough alkalinity to prevent

boiler corrosion.

In addition, as supplementary measures an internal treatment should prevent

corrosion and scaling of the feedwater system and protect against corrosion in the

steam condensate systems.

During the conditioning process, which is an essential complement to the water

treatment program, specific doses of conditioning products are added to the

water. The commonly used products include:

Phosphates-dispersants, polyphosphates-dispersants (softening chemicals):

reacting with the alkalinity of boiler water, these products neutralize the hardness

of water by forming tricalcium phosphate, and insoluble compound that can be

disposed and blow-down on a continuous basis or periodically through the bottom

of the boiler.

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Natural and synthetic dispersants (Anti-scaling agents): increase the dispersive

properties of the conditioning products.

Sequestering agents: such as inorganic phosphates, which act as inhibitors and

implement a threshold effect.

Oxygen scavengers: sodium sulfite, tannis, hydrazine, hydroquinone/progallol-

based derivatives, hydroxylamine derivatives, hydroxylamine derivatives, ascorbic

acid derivatives, etc. These scavengers, catalyzed or not, reduce the oxides and

dissolved oxygen. Most also passivate metal surfaces. The choice of product and

the dose required will depend on whether a deaerating heater is used.

Anti-foaming or anti-priming agents: mixture of surface-active agents that modify

the surface tension of a liquid, remove foam and prevent the carryover of fine

water particles in the steam.

The softening chemicals used include soda ash, caustic and various types of

sodium phosphates. These chemicals react with calcium and magnesium

compounds in the feed water. Sodium silicate is used to react selectively with

magnesium hardness. Calcium bicarbonate entering with the feed water is broken

down at boiler temperatures or reacts with caustic soda to form calcium

carbonate. Since calcium carbonate is relatively insoluble it tends to come out of

solution.

Sodium carbonate partially breaks down at high temperature to sodium hydroxide

(caustic) and carbon dioxide. High temperatures in the boiler water reduce the

solubility of calcium sulfate and tend to make it precipitate out directly on the

boiler metal as scale. Consequently calcium sulfate must be reacted upon

chemically to cause a precipitate to form in the water where it can be conditioned

and removed by blow-down. Calcium sulfate is reacted on either by sodium

carbonate, sodium phosphate or sodium silicate to form insoluble calcium

carbonate, phosphate or silicate. Magnesium sulfate is reacted upon by caustic

soda to form a precipitate of magnesium hydroxide. Some magnesium may react

with silica to form magnesium silicate. Sodium sulfate is highly soluble and

remains in solution unless the water is evaporated almost to dryness.

Sludge

Sludge is the mud-like residue from the chemical treatment of hardness in the

water and should be expected as the normal by-product of water treatment.

There are two general approaches to conditioning sludge inside a boiler: by

coagulation or dispersion. When the total amount of sludge is high (as the result

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of high feedwater hardness) it is better to coagulate the sludge to form large

flocculent particles. This can be removed by blow-down. The coagulation can be

obtained by careful adjustment of the amounts of alkalis, phosphates and organics

used for treatment, based on the feedwater analysis.

When the amount of sludge is not high (low feed water hardness) it is preferable

to use a higher percentage of phosphates in the treatment. Phosphates form

separated sludge particles. A higher percentage of organic sludge dispersants is

used in the treatment to keep the sludge particles dispersed throughout the boiler

water.

The materials used for conditioning sludge include various organic materials of the

tannin, lignin or alginate classes. It is important that these organics are selected

and processed, so that they are both effective and stand stable at the boiler

operating pressure. Certain synthetic organic materials are used as anti-foam

agents. The chemicals used to scavenge oxygen include sodium sulfite (Na2SO3)

and hydrazine (N2H4). Various combinations of polyphosphates and organics are

used for preventing scale and corrosion in feedwater systems. Volatile neutralizing

amines and filming inhibitors are used for preventing condensate corrosion.

Chemical feeding methods

Common internal chemical feeding methods include the use of chemical solution

tanks and proportioning pumps or special ball briquette chemical feeders. In

general, softening chemicals (phosphates, soda ash, caustic, etc.) are added

directly to the feedwater at a point near the entrance to the boiler drum. They

may also be fed through a separate line discharging in the feedwater drum of the

boiler.

The chemicals should discharge in the feedwater section of the boiler so that

reactions occur in the water before it enters the steam generating area. Softening

chemicals may be added continuously or intermittently depending on feedwater

hardness and other factors.

Chemicals added to react with dissolved oxygen (sulfate, hydrazine, etc.) and

chemicals used to prevent scale and corrosion in the feedwater system

(polyphosphates, organics, etc.) should be fed in the feedwater system as

continuously as possible.

Chemicals used to prevent condensate system corrosion may be fed directly to the

steam or into the feedwater system, depending on the specific chemical used.

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Continuous feeding is preferred but intermittent application will suffice in some

cases.

Within the boiler

At the elevated temperatures and pressures within a boiler, water exhibits

different physical and chemical properties than those observed at room

temperature and atmospheric pressure.

Chemicals may be added to maintain pH levels, to prevent foaming, to consume

oxygen before it corrodes the boiler, to precipitate dissolved solids before they

form scale on steam-generating surfaces, and to remove those precipitates from

the vicinity of the steam-generating surfaces.

Pre-treatment

Raw water used in the boiler shall always be evaporated. Normal water can only

be used in emergency with special arrangements. This way, the hardness and

salinity of water will never get very high. Salinity after evaporator shall

automatically be controlled with a salinometer.

Gas removal

Many boilers recycle condensed steam for re-use within the boiler. Steam

condensate is distilled water, but it may contain dissolved gases. A deaerator is

often used to convert condensate to feed water by removing potentially damaging

gases including oxygen, carbon dioxide, ammonia and hydrogen sulfide.

A closed system equipped with a thermal degas unit is recommended for a feed

water tank. This ensures that the amount of gases dissolved in feed and

condensate water stays at the minimum. If a closed system cannot be arranged,

the open feed water tank shall be equipped with direct steam heating, in such a

way that the settling value of temperature is about 90 oC. In each system, gases

separate from water thermally and are blown out through the blow-out pipe.

Chemicals

Feed water is treated with chemicals, in order to bind hardness and residual

oxygen, and to control pH. For the binding of water hardness, trisodium

phosphate is used (Na3PO4), which at the same time, also raises the pH value of

water. The final adjustment of pH is done with alkali (NaOH).

For the binding of oxygen, hydrazine or sodium sulfate (Na2SO3) can be used.

Hydrazine has more advantages, since it as a compound flowing with steam, also

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protects condensate pipelines. Sodium sulfate is not poisonous and is suitable for

use in boilers with working pressure below 40 bar. This compound does not

evaporate in the boiler and does not give the same level of protection to the

condensate piping as hydrazine.

Control of salinity

The salinity of boiler water is maintained within ratings by means of periodical

blow-out. The salinity of feed water is controlled automatically by a salinometer.

Standard values

Using a UNITOR water treatment kit, the recommended values for boiler water

are:

Alkalinity 100 - 300 ppm max

Chlorides 200 ppm max

pH 9.5 – 11

Water and Steam Formed Deposits

Deposits can occur anywhere if water or steam is present in a boiler. While wall

and screen tubes are usually the most heavily fouled, roof and floor tubes often

contains deposits as well. Super heaters and re-heaters frequently contains

deposits that are formed elsewhere and are carried into the systems with boiler

water. Steam is not often generated in economizers. Deposits in these tubes are

usually made up of corrosion products moved from their origination sites.

Deposition can be substantial during steam generation. Tube orientation can

influence the location and amount of deposition. Deposits are usually heaviest on

the hot side of steam-generating tubes.

Carryover

If a boiler is mal-operated there is risk of water containing solids passing over the

steam. This is usually caused by sudden pressure drops coupled with high "take

off" and aggravated by high water levels. If the boiler water is a high solid's levels,

the risk of carryover is greatly increased as water being denser will rise and foam

more rapidly.

Thermal shock derived from carry over can damage valves and other equipment as

globules of water in the steam strike components creating very sudden

temperature changes. The physical impact of water droplets can seriously damage

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components. This is especially important in the case of vessels which have

auxiliary turbines fitted.

The long term effect of carryover is the deposition of contaminants. These can

result in seizure of valves spindles, damage to seats, corrosion and again, in the

case of turbines, a build-up on the nozzles and blades changing designed shapes,

which can seriously reduce the machine's efficiency and cause unbalance. A motor

vessel equipped with turbine machinery must be especially alert to symptom's

causes and remedies for carry over.

Corrosion

Corrosion in low pressure boilers can be caused by dissolved oxygen, acidity and

excessive alkalinity. Water treatment therefore should remove the dissolved

oxygen and maintain the boiler water with the appropriate pH and alkalinity

levels.

Carbonate and bicarbonate alkalinities are decomposed by heat in boiler water

releasing carbon dioxide into the steam. This gas combines with the condensed

steam in process equipment and return lines to form carbonic acid. This depresses

the pH value of the condensate returns and results in corrosive attack on the

equipment and piping.

Boiler Scale Control

Scale is any hard water-formed deposit on the waterside surfaces of the boiler.

Most scale is a build-up of water hardness particles deposited on the boiler

tube walls and other heated surfaces.

Scale build-up can reduce boiler water circulation, cause overheating, tube

failure, and waste fuel.

One sure way to prevent boiler scale build-up is to follow a regular schedule of

water testing and treatment application. For scale control in boilers, water tests

usually run are TDS, OH, and phosphate. These tests are all closely tied together

and are all affected by blow-down, therefore, before interpreting any of these

tests individually, run all of them.

There is a direct relationship between the amount of TDS in the boiler and

scale control, foaming and carryover. Therefore, the boiler water TDS should

be kept within a practical working range. High TDS in boiler water indicates not

enough continuous blow-down. Low TDS indicates too much continuous blow-

down.

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The major function of 'OH' alkalinity in the boiler water is to create proper

conditions for scale control reactions. If the OH is below established control limits,

converting and precipitating scaling impurities won't be fully accomplished.

Corrective actions should not be taken until all your water tests are run

and you have interpreted your reading.

Hotwell Temperature Control

Very few motor vessels have deaerators fitted to reduce oxygen in the boiler feed.

Those that have still require an oxygen scavenger but use less. Dissolved oxygen

can be greatly reduced by maintaining high hotwelI temperatures approaching

boiling point. This is due to the fact that dissolved oxygen levels decrease as water

temperatures approach boiling point. The excess oxygen is released to

atmosphere at the tank surface.

Many systems are operated with no control of this temperature. Hotwell’s are

often over-cooled or the other extreme where they are boiling, which is a direct

waste of energy as water vapour is released to the atmosphere.

The over-cooled hotwell leads to high oxygen levels and also means that a loss of

thermal energy has taken place. Ideally the temperature is controlled at 80-90 oC,

either by bypassing the drain cooler, or reducing cooling water flow, dependant

on system design. Very often, the maximum acceptable temperature, prior to

wasteful loss of vapour is a function of feed pump design.

In view of this, the ideal temperature for any particular vessel must be evaluated

with respect to the risk of feed pump cavitation caused by "boil off' of feed water

at the low pressure area of the pump impeller suction. Experience indicates that

80 oC can be safely used on most motor vessels.

Please remember that this form of control reduces oxygen and therefore requires

less chemical products, but it also means that less energy is required in the

auxiliary boiler or exhaust gas economiser to produce steam. Thus, it is a

significant fuel saving device, where an oil fired unit is operating.

This also reduces the risk of reaching "dew point" on gas side of the exhaust gas

economiser. This in turn will greatly reduce corrosion in that area.

Blow-down control

Blow-down is necessary to lower the boiler water concentration by removing

dissolved and suspended solids. Without controlled blow-down, oil solids in the

boiler water would build-up. Excessive build-up can cause priming and carryover

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and could choke boiler tubes and headers with sludge, resulting in poor

circulation, over-heating and possible tube failures.

When chemicals are added to boiler water to protect the internals, it is obvious

that an increase in dissolved solids will occur. As the treatment reacts with the

contaminants in the water, sludge is formed. Additionally, solids, dissolved and

suspended, are carried into the boiler by the make-up water, and concentration of

these continues. Eventually there is a need for blow-down and it is necessary to

monitor this rate of concentration. A positive method of determining total

dissolved solids of boiler water is the measurement of specific conductance using

a dissolved solids meter.

Blow-down is conducted depending upon the degree of solids by the following

methods:

Continuous Blow-down: Used when dissolved solids are high. This method is

usually adopted through the sampling line, if a continuous blow-down line is not

installed, and can safely be used when a boiler is steaming.

Bottom Flash Blow: When giving a boiler a bottom flash blow, all fires must be

extinguished to prevent blistering of tubes, due to upset circulation. Bottom flash

blows are given when quick dilution of boiler water is required and to remove

sludge. Boilers should be allowed to cool and pressure lowered to no more than

75% of working pressure. This allows suspended solids to drop to the mud drum

so they can be removed when the blow-down valve is opened.

The blow-down valve should be opened quickly and immediately closed to

prevent boiler tube damage. Boiler should be allowed to stand for 5 minutes,

which allows more solids to gravitate to mud drum and blow-down should be

repeated by quickly opening and closing bottom blow-down valve. This procedure

should be repeated allowing about 5 minutes between each blow, until desired

quantity of sludge has been removed or replaced.

It should be stressed that too little blow-down is dangerous for reasons already

stated and excessive blow-down is costly in the form of wasted water, heat, fuel

and chemicals.

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6666. . . . MAIN PROBLEMS IN BOILERSMAIN PROBLEMS IN BOILERSMAIN PROBLEMS IN BOILERSMAIN PROBLEMS IN BOILERS CAUSED BY WATERCAUSED BY WATERCAUSED BY WATERCAUSED BY WATER

The principal difficulties caused by water in boiler are:

• Scaling

• Foaming and priming

• Corrosion

SCALING IN BOILERS

Boiler scale is caused by impurities being precipitated out of the water directly on

heat transfer surfaces or by suspended matter in water settling out on the metal

and becoming hard and adherent. Evaporation in a boiler causes impurities to

concentrate. This interferes with heat transfers and may cause hot spots, leading

to local overheating.

Scaling mechanism is the exceeding of the

solubility limits of mineral substances due to

elevated temperature and solids concentration at

the tube/water interface. The deposition of

crystalline precipitates on the walls of the boiler

interferes with heat transfer and may cause hot

spots, leading to local overheating. The less heat

they conduct, the more dangerous they are.

Common feed water contaminants that can form

boiler deposits include calcium, magnesium, iron,

aluminium, and silica. Scale is formed by salts that

have limited solubility but are not totally insoluble

in boiler water. These salts reach the deposit site

in a soluble form and precipitate.

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The values corresponding to their thermal conductivity are:

Steel 15 kcal/ m2.h per degree C

CaSO4 1 - 2 kcal/ m2.h per degree C

CaCO3 0.5 - 1 kcal/ m2.h per degree C

SiO2 0.2 - 0.5 kcal/m2.h per degree C

Scaling is mainly due to the presence of calcium and magnesium salts (carbonates

or sulfates), which are less soluble hot than cold, or to the presence of too high

concentration of silica in relation to the alkalinity of the water in the boiler.

A carbonate deposit is usually granular and sometimes of a very porous nature.

The crystals of calcium carbonate are large but usually are matted together with

finely divided particles of other materials so that the scale looks dense and

uniform. Dropping it in a solution of acid can easily identify a carbonate deposit.

Bubbles of carbon dioxide will effervesce from the scale.

A sulfate deposit is much harder and more dense than a carbonate deposit

because the crystals are smaller and cement together tighter. A sulfate deposit is

brittle, does not pulverize easily, and does not effervesce when dropped into acid.

A high silica deposit is very hard, resembling porcelain. The crystal of silica is

extremely small, forming a very dense and impervious scale. This scale is

extremely brittle and very difficult to pulverize. It is not soluble in hydrochloric

acid and is usually very light coloured.

Iron deposits, due either to corrosion or iron contamination in the water, are very

dark coloured. Iron deposits in boilers are most often magnetic. They are soluble

in hot acid giving a dark brown coloured solution.

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If unchecked, scaling causes progressive lowering of the boiler efficiency by heat

retardation, acting as an insulator. Eventually, scale built-up will cause the tube to

overheat and rupture.

Boiler deposits can also cause plugging or partial obstruction of corrosive attack

underneath the deposits may occur. In general, boiler deposits can cut operating

efficiency, produce boiler damage, cause unscheduled boiler outages, and

increase cleaning expense.

The first anti-scaling preventative measure is to supply good quality demineralised

water as make-up feed water. The purer the feed water is, the weaker the driving

mechanism to form scale. Scale-forming minerals that do enter the boiler can be

rendered harmless by internal chemical treatment. A long-established technique is

to detach the hardness cations, magnesium and calcium, from the scale forming

minerals and to replace them with sodium ions.

Presence of Silica

Silica can vaporize into the steam at operating pressures as low as 28 bars. Its

solubility in steam increases with increased temperature; therefore, silica

becomes more soluble as steam is superheated. The conditions under which

vaporous silica carryover occurs have been thoroughly investigated and

documented. Researchers have found that for any given set of boiler conditions

using demineralized or evaporated quality make-up water, silica is distributed

between the boiler water and the steam at a defined ratio. This ratio depends on

two factors: boiler pressure and boiler water pH. The value of the ratio increases

almost logarithmically with increasing pressure and decreases with increasing pH.

If the silica enters the boiler water, the usual corrective action is to increase boiler

blow-down, to decrease it to acceptable levels and then to correct the condition

that caused the silica contamination.

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FOAMING AND PRIMING IN BOILERS

Boiler water carryover is the contamination of the steam with boiler-water solids.

Bubbles or froth actually build-up on the surface of the boiler water and pass out

with the steam. This is called foaming and it is caused by high concentration of

any solids in the boiler water. It is generally believed, however, that specific

substances such as alkalis, oils, fats, greases, certain types of organic matter and

suspended solids are particularly conducive to foaming.

In theory, suspended solids collect in the surface film surrounding a steam bubble

and make it tougher. The steam bubble therefore resists breaking and builds up

foam. It is believed that the finer the suspended particles the greater their

collection in the bubble.

Priming is the carryover of varying amounts of droplets of water in the steam

(foam and mist), which lowers the energy efficiency of the steam and leads to the

deposit of salt crystals on the super heaters and in the turbines. Priming may be

caused by improper construction of boiler, excessive ratings, or sudden

fluctuations in steam demand. Priming is sometimes aggravated by impurities in

the boiler-water.

Priming is common cause of high levels of boiler water carryover and is governed

by alkalinity, the presence of certain organic substances and by total salinity or

TDS. The degree of priming also depends on the design of the boiler and its

steaming rate.

The most common measure to prevent foaming and priming is to maintain the

concentration of solids in the boiler water at reasonably low levels. Avoiding high

water levels, excessive boiler loads, and sudden load changes also helps. Very

often contaminated condensate returned to the boiler system causes carryover

problems. In these cases the condensate should be temporarily wasted until the

source of contamination is found and eliminated. The use of chemical anti-

foaming and anti-priming agents, mixtures of surface-active agents that modify

the surface tension of a liquid, remove foam and prevent the carryover of fine

water particles in the stream, can be very effective in preventing carryover due to

high concentrations of impurities in the boiler-water.

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CORROSION IN BOILERS

Corrosion is one of the main causes of reduced reliability in steam generating

systems. It is estimated that problems due to boiler system corrosion cost industry

billions of euros per year.

Many corrosion problems occur in the hottest areas of the boiler, the water wall,

screen, and superheater tubes. Other common problem areas include deaerators,

feedwater heaters, and economizers.

Methods of corrosion control vary depending upon the type of corrosion

encountered. The most common causes of corrosion are dissolved gases (primarily

oxygen and carbon dioxide), underdeposit attack, low pH, and attack of areas

weakened by mechanical stress, leading to stress and fatigue cracking.

These conditions may be controlled through the following procedures:

• Maintenance of proper pH and alkalinity levels

• Control of oxygen and boiler feedwater contamination

• Reduction of mechanical stresses

• Operation within design specifications, especially for temperature and

pressure

• Proper precautions during start-up and shutdown

• Effective monitoring and control

CORROSION TENDENCIES OF BOILER SYSTEM COMPONENTS

Most industrial boiler and feedwater systems are constructed of carbon steel.

Many have copper alloy and/or stainless steel feedwater heaters and condensers.

Some have stainless steel superheater elements.

Proper treatment of boiler feedwater effectively protects against corrosion of

feedwater heaters, economizers, and deaerators.

The consensus is that feedwater oxygen, iron, and copper content should be very

low (e.g., less than 7 ppb oxygen, 20 ppb iron, and 15 ppb copper for a 60 bar

boiler) and that pH should be maintained between 8.5 and 9.5 for system

corrosion protection.

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In order to minimize boiler system corrosion, an understanding of the operational

requirements for all critical system components is necessary.

Feedwater Heaters

Boiler feedwater heaters are designed to improve boiler efficiency by extracting

heat from streams such as boiler water blow-down and turbine extraction or

excess exhaust steam. Feedwater heaters are generally classified as low-pressure

(ahead of the deaerator), high-pressure (after the deaerator), or deaerating

heaters.

Regardless of feedwater heater design, the major problems are similar for all

types. The primary problems are corrosion, due to oxygen and improper pH, and

erosion from the tube side or the shell side. Due to the temperature increase

across the heater, incoming metal oxides are deposited in the heater and then

released during changes in steam load and chemical balances. Stress cracking of

welded components can also be a problem. Erosion is common in the shell side,

due to high-velocity steam impingement on tubes and baffles.

Corrosion can be minimized through proper design (to minimize erosion), periodic

cleaning, control of oxygen, proper pH control, and the use of high-quality

feedwater (to promote passivation of metal surfaces).

Deaerators

Deaerators are used to heat feedwater and reduce oxygen and other dissolved

gases to acceptable levels. Corrosion fatigue at or near welds is a major problem

in deaerators. Most corrosion fatigue cracking has been reported to be the result

of mechanical factors, such as manufacturing procedures, poor welds, and lack of

stress-relieved welds. Operational problems such as water/steam hammer can

also be a factor.

Effective corrosion control requires the following practices:

• Regular monitoring of operation

• Minimization of stresses during start-up

• Maintenance of stable temperature and pressure levels

• Control of dissolved oxygen and pH in the feedwater

• Regular out-of-service inspection using established non-destructive

techniques

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Other forms of corrosive attack in deaerators include stress corrosion cracking of

the stainless steel tray chamber, inlet spray valve spring cracking, corrosion of

vent condensers due to oxygen pitting, and erosion of the impingement baffles

near the steam inlet connection.

Economizers

Economizer corrosion control involves procedures similar to those employed for

protecting feedwater heaters.

Economizers help to improve boiler efficiency by extracting heat from flue gases

discharged from the fireside of a boiler. Economizers can be classified as non-

steaming or steaming. In a steaming economizer, 5-20% of the incoming

feedwater becomes steam. Steaming economizers are particularly sensitive to

deposition from feedwater contaminants and resultant under-deposit corrosion.

Erosion at tube bends is also a problem in steaming economizers.

Oxygen pitting, caused by the presence of oxygen and temperature increase, is a

major problem in economizers; therefore, it is necessary to maintain essentially

oxygen-free water in these units. The inlet is subject to severe pitting, because it is

often the first area after the deaerator to be exposed to increased heat.

Whenever possible, tubes in this area should be inspected closely for evidence of

corrosion.

Economizer heat transfer surfaces are subject to corrosion product build-up and

deposition of incoming metal oxides. These deposits can slough off during

operational load and chemical changes.

Corrosion can also occur on the gas side of the economizer due to contaminants in

the flue gas, forming low-pH compounds. Generally, economizers are arranged for

downward flow of gas and upward flow of water. Tubes that form the heating

surface may be smooth or provided with extended surfaces.

Superheaters

Superheater corrosion problems are caused by a number of mechanical and

chemical conditions. One major problem is the oxidation of superheater metal due

to high gas temperatures, usually occurring during transition periods, such as

start-up and shutdown. Deposits due to carryover can contribute to the problem.

Resulting failures usually occur in the bottom loops, the hottest areas of the

superheater tubes.

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Oxygen pitting, particularly in the pendant loop area, is another major corrosion

problem in superheaters. It is caused when water is exposed to oxygen during

downtime. Close temperature control helps to minimize this problem. In addition,

a nitrogen blanket and chemical oxygen scavenger can be used to maintain

oxygen-free conditions during downtime.

TYPES OF CORROSION

Corrosion control techniques vary according to the type of corrosion encountered.

Major methods of corrosion control include maintenance of the proper pH,

control of oxygen, control of deposits, and reduction of stresses through design

and operational practices.

Galvanic Corrosion

Galvanic corrosion occurs when a metal or alloy is electrically coupled to a

different metal or alloy.

The most common type of galvanic corrosion in a boiler system is caused by the

contact of dissimilar metals, such as iron and copper. These differential cells can

also be formed when deposits are present. Galvanic corrosion can occur at welds

due to stresses in heat-affected zones or the use of different alloys in the welds.

Anything that results in a difference in electrical potential at discrete surface

locations can cause a galvanic reaction. Causes include:

• Scratches in a metal surface

• Differential stresses in a metal

• Differences in temperature

• Conductive deposits

Pitting of boiler tube banks has been encountered due to metallic copper

deposits. Such deposits may form during acid cleaning procedures if the

procedures do not completely compensate for the amount of copper oxides in the

deposits or if a copper removal step is not included. Dissolved copper may be

plated out on freshly cleaned surfaces, establishing anodic corrosion areas and

forming pits, which are very similar to oxygen pits in form and appearance. This

process is illustrated by the following reactions involving hydrochloric acid as the

cleaning solvent.

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Magnetite is dissolved and yields an acid solution containing both ferrous (Fe²+)

and ferric (Fe³+) chlorides (ferric chlorides are very corrosive to steel and copper)

Fe3O4 + 8HCl →→→→ FeCl2 + 2FeCl3 + 4H2O

magnetite hydrochloric acid ferrous chloride ferric chloride water

Metallic or elemental copper in boiler deposits is dissolved in the hydrochloric acid

solution by the following reaction:

FeCl3 + Cu →→→→ CuCl + FeCl2

ferric chloride copper cuprous chloride ferrous chloride

Once cuprous chloride is in solution, it is immediately redeposited as metallic

copper on the steel surface according to the following reaction:

2CuCl + Fe →→→→ FeCl2 + 2Cu0

cuprous chloride iron ferrous chloride copper oxide

Thus, hydrochloric acid cleaning can cause galvanic corrosion unless the copper is

prevented from plating on the steel surface. A complexing agent is added to

prevent the copper from redepositing. The following chemical reaction results:

FeCl3 + Cu + Complexing Agent →→→→ FeCl2 + CuCl

ferric chloride copper ferrous chloride cuprous chloride complex

This can take place as a separate step or during acid cleaning. Both iron and the

copper are removed from the boiler, and the boiler surfaces can then be

passivated.

In most cases, the copper is localized in certain tube banks and causes random

pitting. When deposits contain large quantities of copper oxide or metallic copper,

special precautions are required to prevent the plating out of copper during

cleaning operations.

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Caustic Corrosion

Concentration of caustic (NaOH) can occur either as a result of steam blanketing

(which allows salts to concentrate on boiler metal surfaces) or by localized boiling

beneath porous deposits on tube surfaces.

Caustic corrosion (gouging) occurs when caustic is concentrated and dissolves the

protective magnetite (Fe3O4) layer. Iron, in contact with the boiler water, forms

magnetite and the protective layer is continuously restored. However, as long as a

high caustic concentration exists, the magnetite is constantly dissolved, causing a

loss of base metal and eventual failure.

Steam blanketing is a condition that occurs when a steam layer forms between

the boiler water and the tube wall. Under this condition, insufficient water

reaches the tube surface for efficient heat transfer. The water that does reach the

overheated boiler wall is rapidly vaporized, leaving behind a concentrated caustic

solution, which is corrosive.

Porous metal oxide deposits also permit the development of high boiler water

concentrations. Water flows into the deposit and heat applied to the tube causes

the water to evaporate, leaving a very concentrated solution. Again, corrosion

may occur.

Caustic attack creates irregular patterns, often referred to as gouges. Deposition

may or may not be found in the affected area.

Boiler feedwater systems using demineralized or evaporated makeup or pure

condensate may be protected from caustic attack through coordinated

phosphate/pH control. Phosphate buffers the boiler water, reducing the chance of

large pH changes due to the development of high caustic concentrations. Excess

caustic combines with disodium phosphate and forms trisodium phosphate.

Sufficient disodium phosphate must be available to combine with all of the free

caustic in order to form trisodium phosphate.

Disodium phosphate neutralizes caustic by the following reaction:

Na2HPO4 + NaOH →→→→ Na3PO4 + H2O

disodium phosphate sodium hydroxide trisodium phosphate water

This results in the prevention of caustic build-up beneath deposits or within a

crevice where leakage is occurring. Caustic corrosion (and caustic embrittlement,

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discussed later) does not occur, because high caustic concentrations do not

develop.

Different forms of phosphate consume or add caustic as the phosphate shifts to

the proper form. For example, addition of monosodium phosphate consumes

caustic as it reacts with caustic to form disodium phosphate in the boiler water

according to the following reaction:

Na2HPO4 + NaOH →→→→ Na2HPO4 + H2O

monosodium phosphate sodium hydroxid disodium phosphate water

Conversely, addition of trisodium phosphate adds caustic, increasing boiler water

pH:

Na3PO4 + H2O →→→→ Na2HPO4 + NaOH

trisodium phosphate water disodium phosphate sodium hydroxide

Control is achieved through feed of the proper type of phosphate to either raise or

lower the pH while maintaining the proper phosphate level. Increasing blow-down

lowers both phosphate and pH. Therefore, various combinations and feed rates of

phosphate, blow-down adjustment, and caustic addition are used to maintain

proper phosphate/pH levels.

Elevated temperatures at the boiler tube wall or deposits can result in some

precipitation of phosphate. This effect, termed "phosphate hideout," usually

occurs when loads increase. When the load is reduced, phosphate reappears.

Clean boiler water surfaces reduce potential concentration sites for caustic.

Deposit control treatment programs, such as those based on chelants and

synthetic polymers, can help provide clean surfaces.

Where steam blanketing is occurring, corrosion can take place even without the

presence of caustic, due to the steam/magnetite reaction and the dissolution of

magnetite. In such cases, operational changes or design modifications may be

necessary to eliminate the cause of the problem.

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Acidic Corrosion

Low make-up or feedwater pH can cause serious acid attack on metal surfaces in

the pre-boiler and boiler system. Even if the original makeup or feedwater pH is

not low, feedwater can become acidic from contamination of the system.

Common causes include the following:

• Improper operation or control of demineralizer cation units

• Process contamination of condensate

• Cooling water contamination from condensers

Acid corrosion can also be caused by chemical cleaning operations. Overheating of

the cleaning solution can cause breakdown of the inhibitor used, excessive

exposure of metal to cleaning agent, and high cleaning agent concentration.

Failure to neutralize acid solvents completely before start-up has also caused

problems.

In a boiler and feedwater system, acidic attack can take the form of general

thinning, or it can be localized at areas of high stress such as drum baffles, "U"

bolts, acorn nuts, and tube ends.

Oxygen Attack

Without proper mechanical and chemical deaeration, oxygen in the feedwater will

enter the boiler. Much is flashed off with the steam; the remainder can attack

boiler metal. The point of attack varies with boiler design and feedwater

distribution. Pitting is frequently visible in the feedwater distribution holes, at the

steam drum waterline, and in downcomer tubes.

Oxygen is highly corrosive when present in hot water. Even small concentrations

can cause serious problems. Because pits can penetrate deep into the metal,

oxygen corrosion can result in rapid failure of feedwater lines, economizers, boiler

tubes, and condensate lines. Additionally, iron oxide generated by the corrosion

can produce iron deposits in the boiler.

Oxygen corrosion may be highly localized or may cover an extensive area. It is

identified by well defined pits or a very pockmarked surface. The pits vary in

shape, but are characterized by sharp edges at the surface. Active oxygen pits are

distinguished by a reddish brown oxide cap (tubercle). Removal of this cap

exposes black iron oxide within the pit.

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Oxygen attack is an electrochemical process that can be described by the

following reactions:

Anode:

Fe →→→→ Fe2+

+ 2e¯

Cathode:

½ O2 + H2O + 2e¯ →→→→ 2OH¯

Overall:

Fe + ½O2 + H2O →→→→ Fe(OH)2

The influence of temperature is particularly important in feedwater heaters and

economizers. A temperature rise provides enough additional energy to accelerate

reactions at the metal surfaces, resulting in rapid and severe corrosion.

At 15°C and atmospheric pressure, the solubility of oxygen in water is

approximately 8 ppm. Efficient mechanical deaeration reduces dissolved oxygen

to 7 ppb or less. For complete protection from oxygen corrosion, a chemical

scavenger is required following mechanical deaeration.

Major sources of oxygen in an operating system include poor deaerator operation,

in-leakage of air on the suction side of pumps, the breathing action of receiving

tanks, and leakage of undeaerated water used for pump seals.

The acceptable dissolved oxygen level for any system depends on many factors,

such as feedwater temperature, pH, flow rate, dissolved solids content, and the

metallurgy and physical condition of the system. Based on experience in

thousands of systems, 3-10 ppb of feedwater oxygen is not significantly damaging

to economizers. This is reflected in industry guidelines.

MECHANICAL CONDITIONS AFFECTING CORROSION

Many corrosion problems are the result of mechanical and operational problems.

The following practices help to minimize these corrosion problems:

• Election of corrosion-resistant metals

• Reduction of mechanical stress where possible (e.g., use of proper

welding procedures and stress-relieving welds)

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• Minimization of thermal and mechanical stresses during operation

• Operation within design load specifications, without over-firing, along

with proper start-up and shutdown procedures

• Maintenance of clean systems, including the use of high-purity

feedwater, effective and closely controlled chemical treatment, and acid

cleaning when required

Caustic Embrittlement

Caustic embrittlement (caustic stress corrosion cracking), or inter-crystalline

cracking, has long been recognized as a serious form of boiler metal failure.

Because chemical attack of the metal is normally undetectable, failure occurs

suddenly-often with catastrophic results.

For caustic embrittlement to occur, three conditions must exist:

• The boiler metal must have a high level of stress

• A mechanism for the concentration of boiler water must be present

• The boiler water must have embrittlement-producing characteristics

Where boiler tubes fail as a result of caustic embrittlement, circumferential

cracking can be seen. In other components, cracks follow the lines of greatest

stress. A microscopic examination of a properly prepared section of embrittled

metal shows a characteristic pattern, with cracking progressing along defined

paths or grain boundaries in the crystal structure of the metal. The cracks do not

penetrate the crystals themselves, but travel between them; therefore, the term

"inter-crystalline cracking" is used.

If boiler water possesses embrittling characteristics, steps must be taken to

prevent attack of the boiler metal. Sodium nitrate is a standard treatment for

inhibiting embrittlement in lower-pressure boiler systems. The inhibition of

embrittlement requires a definite ratio of nitrate to the caustic alkalinity present

in the boiler water. In higher-pressure boiler systems, where demineralized make-

up water is used, embrittling characteristics in boiler water can be prevented by

the use of coordinated phosphate/pH treatment control, described previously

under "Caustic Corrosion." This method prevents high concentrations of free

sodium hydroxide from forming in the boiler, eliminating embrittling tendencies.

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Fatigue Cracking

Fatigue cracking (due to repeated cyclic stress) can lead to metal failure. The

metal failure occurs at the point of the highest concentration of cyclic stress.

Examples of this type of failure include cracks in boiler components at support

brackets or rolled in tubes when a boiler undergoes thermal fatigue due to

repeated start-ups and shutdowns.

Thermal fatigue occurs in horizontal tube runs as a result of steam blanketing and

in water wall tubes due to frequent, prolonged lower header blow-down.

Corrosion fatigue failure results from cyclic stressing of a metal in a corrosive

environment. This condition causes more rapid failure than that caused by either

cyclic stressing or corrosion alone. In boilers, corrosion fatigue cracking can result

from continued breakdown of the protective magnetite film due to cyclic stress.

Corrosion fatigue cracking occurs in deaerators near the welds and heat-affected

zones. Proper operation, close monitoring, and detailed out-of-service inspections

(in accordance with published recommendations) minimize problems in

deaerators.

Steam Side Burning

Steam side burning is a chemical reaction between steam and the tube metal. It is

caused by excessive heat input or poor circulation, resulting in insufficient flow to

cool the tubes. Under such conditions, an insulating superheated steam film

develops. Once the tube metal temperature has reached 400 °C in boiler tubes or

510 - 540 °C in superheater tubes (assuming low alloy steel construction), the rate

of oxidation increases dramatically; this oxidation occurs repeatedly and

consumes the base metal. The problem is most frequently encountered in

superheaters and in horizontal generating tubes heated from the top.

Erosion

Erosion usually occurs due to excessive velocities. Where two-phase flow (steam

and water) exists, failures due to erosion are caused by the impact of the fluid

against a surface. Equipment vulnerable to erosion includes turbine blades, low-

pressure steam piping, and heat exchangers that are subjected to wet steam.

Feedwater and condensate piping subjected to high-velocity water flow are also

susceptible to this type of attack. Damage normally occurs where flow changes

direction.

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METALLIC OXIDES IN BOILER SYSTEMS

Iron and copper surfaces are subject to corrosion, resulting in the formation of

metal oxides. This condition can be controlled through careful selection of metals

and maintenance of proper operating conditions.

Iron Oxide Formation

Iron oxides present in operating boilers can be classified into two major types. The

first and most important is the 0.005 - 0.018 millimetres thick magnetite formed

by the reaction of iron and water in an oxygen-free environment. This magnetite

forms a protective barrier against further corrosion.

Magnetite forms on boiler system metal surfaces from the following overall

reaction:

3Fe + 4H2O →→→→ Fe3O4 + 4H2

iron water magnetite hydrogen

The magnetite, which provides a protective barrier against further corrosion,

consists of two layers. The inner layer is relatively thick, compact, and continuous.

The outer layer is thinner, porous, and loose in structure. Both of these layers

continue to grow due to water diffusion (through the porous outer layer) and

lattice diffusion (through the inner layer). As long as the magnetite layers are left

undisturbed, their growth rate rapidly diminishes.

The second type of iron oxide in a boiler is the corrosion products, which may

enter the boiler system with the feedwater. These are frequently termed

"migratory" oxides, because they are not usually generated in the boiler. The

oxides form an outer layer over the metal surface. This layer is very porous and

easily penetrated by water and ionic species.

Iron can enter the boiler as soluble ferrous ions and insoluble ferrous and ferric

hydroxides or oxides. Oxygen-free, alkaline boiler water converts iron to

magnetite, Fe3O4. Migratory magnetite deposits on the protective layer and is

normally gray to black in color.

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Copper Oxide Formation

A truly passive oxide film does not form on copper or its alloys. In water, the

predominant copper corrosion product is cuprous oxide (Cu2O). A typical

corrosion reaction follows:

8Cu + O2 + 2H2O →→→→ 4Cu2O + 2H2

copper oxygen water cuprous oxide hydrogen

The oxide that develops on the copper surfaces is comprised of two layers. The

inner layer is very thin, adherent, nonporous, and comprised mostly of cupric

oxide (CuO). The outer layer is thick, adherent, porous and comprised mainly of

cuprous oxide (Cu2O). The outer layer is formed by breakup of the inner layer. At a

certain thickness of the outer layer, an equilibrium exists at which the oxide

continually forms and is released into the water.

Maintenance of the proper pH, elimination of oxygen, and application of metal-

conditioning agents can minimize the amount of copper alloy corrosion.

Metal Passivation

The establishment of protective metal oxide layers through the use of reducing

agents (such as hydrazine, hydroquinone, and other oxygen scavengers) is known

as metal passivation or metal conditioning. Although "metal passivation" refers to

the direct reaction of the compound with the metal oxide and "metal

conditioning" more broadly refers to the promotion of a protective surface, the

two terms are frequently used interchangeably.

The reaction of hydrazine and hydroquinone, which leads to the passivation of

iron-based metals, proceeds according to the following reactions:

N2H4 + 6Fe2O3 →→→→ 4Fe3O4 + 2H2O + N2

hydrazine hematite magnetite water nitrogen

C6H4 (OH)2 + 3Fe2O3 →→→→ 2Fe3O4 + C6H4O2 + H2O

hydroquinone hematite magnetite benzoquinone water

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Similar reactions occur with copper-based metals:

N2H4 + 4CuO →→→→ 2Cu2O + 2H2O + N2

hydrazine cupric oxide cuprous oxide water nitrogen

C6H6O2 + 2CuO →→→→ Cu2O + C6H6O2 + H2O

Hydroquinone cupric oxide cuprous oxide benzoquinone water

Magnetite and cuprous oxide form protective films on the metal surface. Because

these oxides are formed under reducing conditions, removal of the dissolved

oxygen from boiler feedwater and condensate promotes their formation. The

effective application of oxygen scavengers indirectly leads to passivated metal

surfaces and less metal oxide transport to the boiler whether or not the scavenger

reacts directly with the metal surface.

A significant reduction in feedwater oxygen and metal oxides can occur with

proper application of oxygen scavengers.

CORROSION CONTROL FACTORS

Steel and Steel Alloys

Protection of steel in a boiler system depends on temperature, pH, and oxygen

content. Generally, higher temperatures, high or low pH levels, and higher oxygen

concentrations increase steel corrosion rates.

Mechanical and operational factors, such as velocities, metal stresses, and severity

of service can strongly influence corrosion rates. Systems vary in corrosion

tendencies and should be evaluated individually.

Copper and Copper Alloys

Many factors influence the corrosion rate of copper alloys:

• Temperature

• pH

• Oxygen concentration

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• Amine concentration

• Ammonia concentration

• Flow rate

The impact of each of these factors varies depending on characteristics of each

system. Temperature dependence results from faster reaction times and greater

solubility of copper oxides at elevated temperatures. Maximum temperatures

specified for various alloys range from 90 to 150 °C.

Methods of minimizing copper and copper alloy corrosion include:

• Replacement with a more resistant metal

• Elimination of oxygen

• Maintenance of high-purity water conditions

• Operation at the proper pH level

• Reduction of water velocities

• Application of materials which passivate the metal surfaces

pH Control

Maintenance of proper pH throughout the boiler feedwater, boiler, and

condensate systems is essential for corrosion control. Most low-pressure boiler

system operators monitor boiler water alkalinity because it correlates very closely

with pH, while most feedwater, condensate, and high-pressure boiler water

requires direct monitoring of pH. Control of pH is important for the following

reasons:

• Corrosion rates of metals used in boiler systems are sensitive to

variations in pH

• Low pH or insufficient alkalinity can result in corrosive acidic attack

• High pH or excess alkalinity can result in caustic gouging/cracking and

foaming, with resultant carryover

• Speed of oxygen scavenging reactions is highly dependent on pH levels

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The pH or alkalinity level maintained in a boiler system depends on many factors,

such as system pressure, system metals, feedwater quality, and type of chemical

treatment applied.

The corrosion rate of carbon steel at feedwater temperatures approaches a

minimum value in the pH range of 9.2 - 9.6. It is important to monitor the

feedwater system for corrosion by means of iron and copper testing. For systems

with sodium zeolite or hot lime softened makeup, pH adjustment may not be

necessary. In systems that use deionized water makeup, small amounts of caustic

soda or neutralizing amines, such as morpholine and cyclohexylamine, can be

used.

In the boiler, either high or low pH increases the corrosion rates of mild steel. The

pH or alkalinity that is maintained depends on the pressure, make-up water

characteristics, chemical treatment, and other factors specific to the system.

The best pH for protection of copper alloys is somewhat lower than the optimum

level for carbon steel. For systems that contain both metals, the condensate and

feedwater pH is often maintained between 8.8 and 9.2 for corrosion protection of

both metals. The optimum pH varies from system to system and depends on many

factors, including the alloy used.

To elevate pH, neutralizing amines should be used instead of ammonia, which

(especially in the presence of oxygen) accelerates copper alloy corrosion rates.

Also, amines form protective films on copper oxide surfaces that inhibit corrosion.

Oxygen Control

Chemical Oxygen Scavengers. The oxygen scavengers most commonly used in

boiler systems are sodium sulfite, sodium bisulfite, hydrazine, catalyzed versions

of the sulfites and hydrazine, and organic oxygen scavengers, such as

hydroquinone and ascorbate.

It is of critical importance to select and properly use the best chemical oxygen

scavenger for a given system. Major factors that determine the best oxygen

scavenger for a particular application include reaction speed, residence time in the

system, operating temperature and pressure, and feedwater pH. Interferences

with the scavenger/oxygen reaction, decomposition products, and reactions with

metals in the system are also important factors. Other contributing factors include

the use of feedwater for attemperation, the presence of economizers in the

system, and the end use of the steam. Chemical oxygen scavengers should be fed

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to allow ample time for the scavenger/oxygen reaction to occur. The deaerator

storage system and the feedwater storage tank are commonly used feed points.

In boilers operating below 70 bar, sodium sulfite and a concentrated liquid

solution of catalyzed sodium bisulfite are the most commonly used materials for

chemical deaeration due to low cost and ease of handling and testing. The oxygen

scavenging property of sodium sulfite is illustrated by the following reaction:

2Na2SO3 + O2 →→→→ 2Na2SO4

sodium sulfite oxygen sodium sulfate

Theoretically, 7.88 ppm of chemically pure sodium sulfite is required to remove

1.0 ppm of dissolved oxygen. However, due to the use of technical grades of

sodium sulfite, combined with handling and blow-down losses during normal plant

operation, approximately 10 Kg of sodium sulfite per Kg of oxygen is usually

required. The concentration of excess sulfite maintained in the feedwater or boiler

water also affects the sulfite requirement.

Sodium sulfite must be fed continuously for maximum oxygen removal.

As with any oxygen scavenging reaction, many factors affect the speed of the

sulfite-oxygen reaction. These factors include temperature, pH, initial

concentration of oxygen scavenger, initial concentration of dissolved oxygen, and

catalytic or inhibiting effects. The most important factor is temperature. As

temperature increases, reaction time decreases; in general, every 10 °C increase in

temperature doubles reaction speed. At temperatures of 100 °C and above, the

reaction is rapid. Overfeed of sodium sulfite also increases reaction rate. The

reaction proceeds most rapidly at pH values in the range of 8.5-10.0.

Commercial sodium sulfite is not as faster and efficient in removal of oxygen as

catalyzed sodium sulfite. After 25 seconds of contact, catalyzed sodium sulfite

removed the oxygen completely. Uncatalyzed sodium sulfite removed less than

50% of the oxygen in this same time period. In a boiler feedwater system, this

could result in severe corrosive attack.

The following operational conditions necessitate the use of catalyzed sodium

sulfite:

• Low feedwater temperature

• Incomplete mechanical deaeration

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• Rapid reaction required to prevent pitting in the system

• Short residence time

• Use of economizers

High feedwater sulfite residuals and pH values above 8.5 should be maintained in

the feedwater to help protect the economizer from oxygen attack.

Some natural waters contain materials that can inhibit the oxygen/sulfite reaction.

For example, trace organic materials in a surface supply used for makeup water

can reduce speed of scavenger/oxygen reaction time. The same problem can

occur where contaminated condensate is used as a portion of the boiler

feedwater. The organic materials complex metals (natural or formulated catalysts)

and prevent them from increasing the rate of reaction.

At operating pressures of 70 bar and higher, hydrazine or organic oxygen

scavengers are normally used in place of sulfite. In these applications, the

increased dissolved solids contributed by sodium sulfate (the product of the

sodium sulfite-oxygen reaction) can become a significant problem. Also, sulfite

decomposes in high-pressure boilers to form sulfur dioxide (SO2) and hydrogen

sulfide (H2S). Both of these gases can cause corrosion in the return condensate

system and have been reported to contribute to stress corrosion cracking in

turbines. Hydrazine has been used for years as an oxygen scavenger in high-

pressure systems and other systems in which sulfite materials cannot be used.

Hydrazine is a reducing agent that removes dissolved oxygen by the following

reaction:

N2H4 + O2 →→→→ 2H2O + N2

hydrazine oxygen water nitrogen

Because the products of this reaction are water and nitrogen, the reaction adds no

solids to the boiler water. The decomposition products of hydrazine are ammonia

and nitrogen. Decomposition begins at approximately 200°C and is rapid at 300°C.

The alkaline ammonia does not attack steel. However, if enough ammonia and

oxygen are present together, copper alloy corrosion increases. Close control of the

hydrazine feed rate can limit the concentration of ammonia in the steam and

minimize the danger of attack on copper-bearing alloys. The ammonia also

neutralizes carbon dioxide and reduces the return line corrosion caused by carbon

dioxide.

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Hydrazine is a toxic material and must be handled with extreme care. Because the

material is a suspected carcinogen, federally published guidelines must be

followed for handling and reporting. Because pure hydrazine has a low flash point,

a 35% solution with a flash point of greater than 90°C is usually used.

Theoretically, 1.0 ppm of hydrazine is required to react with 1.0 ppm of dissolved

oxygen. However, in practice 1.5-2.0 parts of hydrazine are required per part of

oxygen.

The factors that influence the reaction time of sodium sulfite also apply to other

oxygen scavengers. The reaction is also dependent upon pH (the optimum pH

range is 9.0-10.0).

In addition to its reaction with oxygen, hydrazine can also aid in the formation of

magnetite and cuprous oxide (a more protective form of copper oxide), as shown

in the following reactions:

N2H4 + 6Fe2O3 →→→→ 4Fe3O4 + N2 + 2H2O

hydrazine hematite magnetite nitrogen water

and

N2H4 + 4CuO →→→→ 2Cu2O + N2 + 2H2O

hydrazine cupric oxide cuprous oxide nitrogen water

Because hydrazine and organic scavengers add no solids to the steam, feedwater

containing these materials is generally satisfactory for use as attemperating or

desuperheating water.

The major limiting factors of hydrazine use are its slow reaction time (particularly

at low temperatures), ammonia formation, effects on copper-bearing alloys, and

handling problems.

Organic Oxygen Scavengers. Several organic compounds are used to remove

dissolved oxygen from boiler feedwater and condensate. Among the most

commonly used compounds are hydroquinone and ascorbate. These materials are

less toxic than hydrazine and can be handled more safely. As with other oxygen

scavengers, temperature, pH, initial dissolved oxygen concentration, catalytic

effects, and scavenger concentration affect the rate of reaction with dissolved

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oxygen. When fed to the feedwater in excess of oxygen demand or when fed

directly to the condensate, some organic oxygen scavengers carry forward to

protect steam and condensate systems.

Hydroquinone is unique in its ability to react quickly with dissolved oxygen, even

at ambient temperature. As a result of this property, in addition to its

effectiveness in operating systems, hydroquinone is particularly effective for use

in boiler storage and during system start-ups and shutdowns. It is also used widely

in condensate systems.

Hydroquinone reacts with dissolved oxygen as shown in the following reactions:

C6H4(OH)2 + O2 →→→→ C6H4O2 + H2O

hydroquinone oxygen benzoquinone water

Benzoquinone reacts further with oxygen to form polyquinones:

C6H4O2 + O2 →→→→ polyquinones

benzoquinone oxygen

These reactions are not reversible under the alkaline conditions found in boiler

feedwater and condensate systems. In fact, further oxidation and thermal

degradation (in higher-pressure systems) leads to the final product of carbon

dioxide. Intermediate products are low molecular weight organic compounds,

such as acetates.

Oxygen Level Monitoring. Oxygen monitoring provides the most effective means

of controlling oxygen scavenger feed rates. Usually, a slight excess of scavenger is

fed. Feedwater and boiler water residuals provide an indication of excess

scavenger feed and verify chemical treatment feed rates. It is also necessary to

test for iron and copper oxides in order to assess the effectiveness of the

treatment program. Proper precautions must be taken in sampling for metal

oxides to ensure representative samples.

Due to volatility and decomposition, measurement of boiler residuals is not a

reliable means of control. The amount of chemical fed should be recorded and

compared with oxygen levels in the feedwater to provide a check on the control of

dissolved oxygen in the system. With sodium sulfite, a drop in the chemical

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residual in the boiler water or a need to increase chemical feed may indicate a

problem. Measures must be taken to determine the cause so that the problem

can be corrected.

Sulfite residual limits are a function of boiler operating pressure. For most low-

and medium-pressure systems, sulfite residuals should be in excess of 20 ppm.

Hydrazine control is usually based on a feedwater excess of 0.05-0.1 ppm. For

different organic scavengers, residuals and tests vary.

MONITORING AND TESTING

Effective corrosion control monitoring is essential to ensure boiler reliability. A

well planned monitoring program should include the following:

• Proper sampling and monitoring at critical points in the system

• Completely representative sampling

• Use of correct test procedures

• Checking of test results against established limits

• A plan of action to be carried out promptly when test results are not

within established limits

• A contingency plan for major upset conditions

• A quality improvement system and assessment of results based on

testing and inspections

Monitoring Techniques

Appropriate monitoring techniques vary with different systems. Testing should be

performed at least once per shift. Testing frequency may have to be increased for

some systems where control is difficult, or during periods of more variable

operating conditions. All monitoring data, whether spot sampling or continuous,

should be recorded.

Boiler feedwater hardness, iron, copper, oxygen, and pH should be measured.

Both iron and copper, as well as oxygen, can be measured on a daily basis. It is

recommended that, when possible, a continuous oxygen meter be installed in the

feedwater system to detect oxygen intrusions. Iron and copper, in particular,

should be measured with care due to possible problems of sample contamination.

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If a continuous oxygen meter is not installed, periodic testing with spot sampling

ampoules should be used to evaluate deaerator performance and potential for

oxygen contamination from pump seal water and other sources.

For the boiler water, the following tests should be performed:

• Phosphate (if used)

• P-alkalinity or pH

• Sulfite (if used)

• Conductivity

Sampling

It is critical to obtain representative samples in order to monitor conditions in the

boiler feedwater system properly. Sample lines, continuously flowing at the

proper velocity and volume, are required. Generally, a velocity of 1,5 mt/sec and a

flow of 800-1000 ml/min are satisfactory. The use of long sample lines should be

avoided. Iron and copper sampling should be approached with extreme care

because of the difficulty of obtaining representative samples and properly

interpreting results. Trends, rather than individual samples, should be used to

assess results. Copper sampling requires special precautions, such as acidification

of the stream. Composite sampling, rather than spot sampling, can also be a

valuable tool to determine average concentrations in a system.

Oxygen sampling should be performed as close to the line as possible, because

long residence time in sampling lines can allow the oxygen scavenger to further

react and reduce oxygen readings. Also, if in-leakage occurs, falsely high data may

be obtained. Sampling for oxygen should also be done at both the effluent of the

deaerator and effluent of the boiler feedwater pump, to verify that oxygen ingress

is not occurring.

Results and Action Required

All inspections of equipment should be thorough and well documented.

Conditions noted must be compared to data from previous inspections. Analytical

results and procedures must be evaluated to ensure that quality standards are

maintained and that steps are taken for continual improvement. Cause-and-effect

diagrams can be used either to verify that all potential causes of problems are

reviewed, or to troubleshoot a particular corrosion-related problem.

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CORROSION PROTECTION DURING DOWNTIME AND STORAGE

Oxygen corrosion in boiler feedwater systems can occur during start-up and

shutdown and while the boiler system is on standby or in storage, if proper

procedures are not followed. Systems must be stored properly to prevent

corrosion damage, which can occur in a matter of hours in the absence of proper

lay-up procedures. Both the water/steam side and the fireside are subject to

downtime corrosion and must be protected.

Off-line boiler corrosion is usually caused by oxygen in-leakage. Low pH causes

further corrosion. Low pH can result when oxygen reacts with iron to form

hydroferric acid. This corrosion product, an acidic form of iron, forms at water-air

interfaces.

Corrosion also occurs in boiler feedwater and condensate systems. Corrosion

products generated both in the pre-boiler section and the boiler may deposit on

critical heat transfer surfaces of the boiler during operation and increase the

potential for localized corrosion or overheating.

The degree and speed of surface corrosion depend on the condition of the metal.

If a boiler contains a light surface coating of boiler sludge, surfaces are less likely

to be attacked because they are not fully exposed to oxygen-laden water.

Experience has indicated that with the improved cleanliness of internal boiler

surfaces, more attention must be given to protection from oxygen attack during

storage. Boilers that are idle even for short time periods (e.g., weekends) are

susceptible to attack.

Boilers that use undeaerated water during start-up and during their removal from

service can be severely damaged. The damage takes the form of oxygen pitting

scattered at random over the metal surfaces. Damage due to these practices may

not be noticed for many years after installation of the unit.

The choice of storage methods depends on the length of downtime expected and

the boiler complexity. If the boiler is to be out of service for a month or more, dry

storage may be preferable. Wet storage is usually suitable for shorter down-time

periods or if the unit may be required to go on-line quickly. Large boilers with

complex circuits are difficult to dry, so they should be stored by one of the wet

storage methods.

Dry Storage

For dry storage, the boiler is drained, cleaned, and dried completely. All horizontal

and non-drainable boiler and superheater tubes must be blown dry with

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compressed gas. Particular care should be taken to purge water from long

horizontal tubes, especially if they have bowed slightly.

Heat is applied to optimize drying. After drying, the unit is closed to minimize air

circulation. Heaters should be installed as needed to maintain the temperature of

all surfaces above the dew point.

Immediately after surfaces are dried, one of the three following desiccants is

spread on water-tight wood or corrosion-resistant trays:

• Quicklime-used at a rate of 0,90 Kg/10 m³ of boiler volume

• Silica gel-used at a rate of 2,5 Kg/10 m³ of boiler volume

• Activated alumina-used at a rate of 4,0 Kg/10 m³ of boiler volume

The trays are placed in each drum of a water tube boiler, or on the top flues of a

fire-tube unit. All manholes, handholes, vents, and connections are blanked and

tightly closed. The boiler should be opened every month for inspection of the

desiccant. If necessary, the desiccant should be renewed.

Wet Storage

For wet storage, the unit is inspected, cleaned if necessary, and filled to the

normal water level with deaerated feedwater.

Sodium sulfite, hydrazine, hydroquinone, or another scavenger is added to control

dissolved oxygen, according to the following requirements:

• Sodium sulfite. 0,36 Kg of sodium sulfite and 0,36 Kg of caustic soda should be

added per 1000 liters of water contained in the boiler (minimum 400 ppm P-

alkalinity as CaCO3 and 200 ppm sulfite as SO3).

• Hydrazine. 0,59 Kg of a 35% solution of hydrazine and 0,012 Kg of ammonia or

0,37 Kg of a 40% solution of neutralizing amine can be added per 1000 liters

(minimum 200 ppm hydrazine and 10.0 pH). Due to the handling problems of

hydrazine, organic oxygen scavengers are normally recommended.

• Hydroquinone. Hydroquinone-based materials are added to achieve

approximately 200 ppm as hydroquinone in previously passivated on-line systems.

In new systems, or those considered to have a poorly formed magnetite film, the

minimum feed rate is 400 ppm as hydroquinone. pH should be maintained at 10.0.

No matter which treatment is used, pH or alkalinity adjustment to minimum levels

is required.

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After chemical addition, with vents open, heat is applied to boil the water for

approximately 1 hour. The boiler must be checked for proper concentration of

chemicals, and adjustments made as soon as possible.

If the boiler is equipped with a non-drainable superheater, the superheater is

filled with high-quality condensate or demineralized water and treated with a

volatile oxygen scavenger and pH control agent. The normal method of filling non-

drainable superheaters is by back-filling and discharging into the boiler. After the

superheater is filled, the boiler should be filled completely with deaerated

feedwater. Morpholine, cyclohexylamine, or similar amines are used to maintain

the proper pH.

If the superheater is drainable or if the boiler does not have a superheater, the

boiler is allowed to cool slightly after firing. Then, before a vacuum is created, the

unit is filled completely with deaerated feedwater.

A surge tank (such as a 208 liters drum) containing a solution of treatment

chemicals or a nitrogen tank at 5 psig pressure is connected to the steam drum

vent to compensate for volumetric changes due to temperature variations.

The drain between the non-return valve and main steam stop valve is left open

wide. All other drains and vents are closed tightly.

The boiler water should be tested weekly with treatment added as necessary to

maintain treatment levels. When chemicals are added, they should be mixed by

one of the following methods:

• Circulate the boiler water with an external pump

• Reduce the water level to the normal operating level and steam the boiler for a

short time

If the steaming method is used, the boiler should subsequently be filled

completely, in keeping with the above recommendations.

Although no other treatment is required, standard levels of the chemical

treatment used when the boiler is operating can be present.

Boilers can be protected with nitrogen or another inert gas. A slightly positive

nitrogen (or other inert gas) pressure should be maintained after the boiler has

been filled to the operating level with deaerated feedwater.

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Storage of Feedwater Heaters and Deaerators

The tube side of a feedwater heater is treated in the same way the boiler is

treated during storage. The shell side can be steam blanketed or flooded with

treated condensate.

All steel systems can use the same chemical concentrations recommended for wet

storage. Copper alloy systems can be treated with half the amount of oxygen

scavenger, with pH controlled to 9.5.

Deaerators are usually steam or nitrogen blanketed. However, they can be

flooded with a lay-up solution as recommended for wet lay-up of boilers. If the

wet method is used, the deaerator should be pressurized with 5 psig of nitrogen

to prevent oxygen ingress.

Cascading Blow-down

For effective yet simple boiler storage, clean, warm, continuous blow-down can be

distributed into a convenient bottom connection on an idle boiler. Excess water is

allowed to overflow to an appropriate disposal site through open vents. This

method decreases the potential for oxygen ingress and ensures that properly

treated water enters the boiler. This method should not be used for boilers

equipped with non-drainable superheaters.

Cold Weather Storage

In cold weather, precautions must be taken to prevent freezing. Auxiliary heat,

light firing of the boiler, cascade lay-up, or dry storage may be employed to

prevent freezing problems. Sometimes, a 50/50 water and ethylene glycol mixture

is used for freeze protection. However, this method requires that the boiler be

drained, flushed, and filled with fresh feedwater prior to start-up.

Fireside Storage

When boilers are removed from the line for extended periods of time, fireside

areas must also be protected against corrosion.

Fireside deposits, particularly in the convection, economizer, and air heater

sections, are hygroscopic in nature. When metal surface temperatures drop below

the dew point, condensation occurs, and if acidic hygroscopic deposits are

present, corrosion can result.

The fireside areas (particularly the convection, economizer, and air heater

sections) should be cleaned prior to storage.

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High-pressure alkaline water is an effective means of cleaning the fireside areas.

Before alkaline water is used for this purpose, a rinse should be made with fresh

water of neutral pH to prevent the formation of hydroxide gels in the deposits

(these deposits can be very difficult to remove).

Following chemical cleaning with a water solution, the fireside should be dried by

warm air or a small fire. If the boiler is to be completely closed up, silica gel or lime

can be used to absorb any water of condensation. As an alternative, metal

surfaces can be sprayed or wiped with a light oil.

If the fireside is to be left open, the metal surfaces must be maintained above the

dew point by circulation of warm air.

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7777. . . . UNEX UNEX UNEX UNEX BOILERBOILERBOILERBOILERSSSS WATER WATER WATER WATER RECOMMENDATRECOMMENDATRECOMMENDATRECOMMENDATIONSIONSIONSIONS

Concept of water treatment

Most important aspects having effect on the safety, working life and security of

boiler plant are the correct treatment and maintenance of water. The quality of

water and functioning of the treatment equipment must be regularly observed

and any potential defects must be immediately eliminated. This way faultless

operation of the plant is ensured.

A book of water values and functioning of devices must also be kept. In case of

potential malfunctioning, conclusions on reasons for them can be drawn on this

basis.

Below there are main instructions for water treatment, normative water values

and methods for measurement.

Pre-treatment:

Raw water used in the boiler plant shall always be evaporated. Normal water can

only be used in emergency with special arrangements. Thus, the hardness and

salinity of water will never get very high. Salinity after evaporator shall

automatically be controlled with a salinometer.

Gas removal:

A closed system equipped with a thermal degas unit is recommended, in the first

place, for a feed water tank. This ensures that the amount of gases dissolved in

feed and condensate water stays at the minimum.

If a closed system cannot be arranged, the open feed water tank shall, however,

be equipped with direct steam heating in such a way that the setting value of

temperature is approx. 90 - 95 °C. In each system gases separate from water

thermally and are blown out through the blow-out pipe.

Chemicals:

Feed water is also treated with chemicals, which are used to bind hardness and

residual oxygen and to control pH.

For the binding of water hardness e.g. trisodium phosphate (Na3PO4) is used,

which, at the same time, also raises the pH value of water.

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The final adjustment of pH is done with alkali (NaOH).

For the binding of oxygene, e.g. hydrazine or sodium sulfate can be used.

Hydrazine has more advantages, since it, as a compound flowing with steam, also

protects condensate pipe lines. ln some countries, however, hydrazine is

considered slightly poisonous and therefore there are restrictions regarding its

use. Sodium sulfate is not poisonous and is suitable for use in boilers with working

pressure below 40 bar. This compound does not evaporate in the boiler and does

not give a same kind of protection to the condensate piping as hydrazine.

Control of salinity:

The salinity of boiler water is maintained within ratings by means of periodical

blow-out. The salinity of feed water is controlled automatically by a salinometer.

Pipings:

The pipe lines of the boiler plant shall be made of steel. Use of copper is restricted

to a minimum. In this way, the risk of galvanic corrosion is as small as possible.

Instructions for use of UNEX Boilers

The following instruction for use and analysing relating to water treatment of

auxiliary steam boilers have been drawn up on the basis of different sources and

practical experience. The facts that must be considered as most important for a

boiler and its devices have been taken under continuous observance. Methods

that have been chosen for analysing are those that can be carried out with simple

and few devices, though the analysis precision has often been reduced in this way.

TREATMENT OF FEED WATER

Treatment of feed water on board can be divided in the following phases:

A. Thermal degassing in order to eliminate oxygen and carbonic acid dissolved in

water. The aim of this is to reduce corrosion in boiler, steam and condensate

piping and related devices.

B. Chemical treatment of water, which can be divided into:

a) Phosphate feed mainly for binding the residual hardness

b) Alkali feed for raising the pH value to reduce corrosion

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c) Hydrazine or Sodium Sulfite feed for eliminating the residual oxygen to reduce

corrosion

In addition to the above, the out-blow arrangement is considered to be part of

water treatment. Furthermore it is presumed that all feed water is led through a

water softener, if evaporated water is not available.

Gas removing and feedwater tank

Feedwater and returning condensate shall flow as evenly as possible into the feed

water tank. At the bottom of the water space in feedwater tank, there must be

arranged feed of steam through an automatic temperature regulator. With the aid

of steam, blow water in the feed water tank is kept moving and hemothermal. It

can also be used to heat up the water quickly, if it has got cool.

Dosing of Trisodium Phosphate (Na3PO4)

The amount of dosing depends of the volume of out-blow and is directly in

proportion to it. The aim is to maintain the P205 content of boiler water between

20-40 mg/l. If the volume of out-blow is approximately 5 %, the amount of

phosphate to be added to feed water is 5 - 10 g/m3. Trisodium Phosphate contains

approximately 19 % of P205.

Dosing of Sodium Hydroxide (Alkali) (NaOH)

If the volume of out-blow is 5 % of the additional water amount, dosing of alkali

can be started with the amount 20 g/m3. If the volume of out-blow is smaller, the

dosing is correspondingly smaller, as well. The rating table shows the boiler water

pH, which should be achieved. In addition to pH also the p-value must be

observed. It may not exceed the value 15.

Dosing of hydrazine or Sodium Sulfite

a) The aim of the dosing is that there is a slight surplus of hydrazine (N2H4) in

boiler water of 0,1 - 0,3 mg/l. Hydrazine is a powerful reducer which changes

together with free oxygen in water into nitrogen and water. Theoretically 1 g of

hydrazine binds 1 g of oxygen, but in practice, at least a tripled value is

recommended.

Hydrazine dissolves as ammonia and nitrogen, if there is not oxygen in water.

Ammonia moves with steam and increases the pH value of the condensate, which

value protects the condensate piping’s from corrosion.

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The need of hydrazine is directly in proportion to oxygen content of water. The

table below shows normative values for dosing of hydrazine. The estimation there

is that hydrazine contains 24 % of N2H4 and the dosing is 300 % of the theoretical

need. When hydrazine with a content of active N2H4 over 24 %, is utilized, dosing

shall be reduced accordingly.

When the feed water temperature is 80 °C, dosing is 30 g of hydrazine per each

ton of feed water and with different temperatures as shown below:

85 °C 20 g / ton

90 °C 18 g / ton

95 °C 15 g / ton

96 °C 13 g / ton

97 °C 10 g / ton

98 °C 7 g / ton

> 99 °C 4 g / ton

b) The aim of the dosing is that there is always Sodium Sulfite in boiler water.

30-60 g/m3 is regarded as a suitable amount. If there is no thermal degassing,

dose must be 50-200 g/m3. The Sodium Sulfite used should be so-called activated

Sodium Sulfite, made for the purpose.

Blow-out

The boiler blow-out is used for maintaining the quality of boiler water within

desired limits, which have been given in the rating table. It is important that the

proportion of out-blown water and additional water remains constant, because

the chemical dosing succeeds only on that condition. On the other hand, the

volume of blow-out should be as small as possible and, however, sufficiently large

to prevent exceeding of critical analysis values in boiler water.

The volume of blow-out can be roughly calculated as the proportion of the

additional water salinity and the biggest allowed salinity of boiler water. If, e.g. the

salinity of additional water is 50 mg/l and biggest allowed concentration of boiler

water is 1000 mg/l, the volume of blow-out is 50/1000 = 0,05 or 5 % of the

additional water volume.

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CONTROL

Chemical analyses are used to control functioning of water treatment equipment

of the boiler plant and dosing of chemicals. In addition, mechanical functioning of

the devices is controlled, as well.

SAMPLING

Before a chemical analysis there is always a sampling to be analysed. The correct

sampling is as important as the analysis itself. The sampling is performed in such a

way that the sample really contains the water to be examined.

Therefore, before sampling, water is let run with considerable speed so long that

it is changed 3-4 times in the sampling pipeline (30 seconds at the minimum) and

only then the actual sample needed for analysing is taken.

It is best to take boiler water sample through a special condensing coil designed

for this purpose. If this is not available, the analysis results must be multiplied by

the following numbers in order to correct the fault caused by evaporation loss:

Boiler pressure bar coefficient:

6 0,88

8 0,86

10 0,84

15 0,81

20 0,7826

RATINGS

The following table shows the water treatment ratings for boilers. While starting

up a new boiler or after a downtime, analyses must be performed more frequently

than stated in the table. After finding out that sampling continuously give the

same results, the analyses can be done according to the table. Hardness of

softened water must be defined the more often the longer the softening filter has

been in use, counted from regeneration.

The table also includes other ratings beside those, for which more detailed

definitions and analysis instructions have been given. This is to give a more

detailed description of the facts to be paid attention to while maintaining the

boiler.

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Recommended analysis values for feed and boiler water:

Boiler pressure: < 15 bar

Feed water

pH daily 8,5 - 9,5

Oxygen 02 mg/l monthly < 0,05

Hardness °dH daily < 0,1

Oil mg/l daily <2

Iron and copper Fe, Cu mg/l monthly < 0,1

Salinity mg/l daily < 100

Boiler water

pH daily 9 - 11,5

p-value mval/l daily 5 - 15

Salinity NaCl mg/l weekly < 1000

Dissolved solid content °Be weekly 0,35

Phosphate mg/I daily 20 - 40

KMn04 consumption mg/l monthly 500

Hydrazine N2H4 mg/I weekly 0,1 - 0,3

Conductivity μS/cm daily < 5000

Pag |76 - 94


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8888. . . . LESSONS LEARNEDLESSONS LEARNEDLESSONS LEARNEDLESSONS LEARNED

Boilers are common equipment in ships and in land installations. There are many

reports and communications available, full of lessons learned that must be

considered and that are strategic to a successful water treatment program.

LESSONS LEARNED - I

Three serious auxiliary boiler explosions have been reported to the Department

and in two cases there was loss of life. The three boilers were of different types

and make.

(a) Vertical smoke tube boiler—combined exhaust and oil fired.

(b) Vertical combined water tube/smoke tube oil fired boiler.

(c) Double evaporation boiler (steam heated low pressure drum exploded).

These boilers contained large amounts of water and at the time of the incident

were 10 to 15 years old.

On investigation it was noted that all had been suffering from general corrosion

and pitting on the waterside for sometime. In two cases large cracks developed

from small crevices next to welding seams in the shell plating due to high oxygen

content in the boiler water over a period.

Special examination of such boilers has been carried out since. In a number of

cases cracks/fractures have been found in the lower section of the water space in

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way of main circumferential seam and downcomers, in way of nozzle connections

and burner throats. It appears that the cracks/fractures are a result of a corrosion

fatigue mechanism, where a corrosive environment has had a significant effect in

conjunction with fatigue stress. Probable causes could be due to boiler water not

being properly treated, open feed system and low feed temperature.

Shipowners are advised that in case of oil fired, exhaust gas or steam heated type

boilers the following items need special attention as they contribute to corrosion

fatigue, development of cracks leading to boiler drum leakage and possible

rupture.

(a) Internal condition of drum with regard to corrosion.

(b) Feed water (hotwell) temperature.

(c) Boiler feed treatment.

Shipowners should advise their ship's staff as follows:

When the boilers are in service

(a) Proper feed treatment should be administered at all times.

(b) The boiler water to be kept alkaline at all times.

(c) It is recommended that the feed water temperature should be kept above 90°C

(it is worth noting that O2 content in feed water may be four times higher at 50°C

than it is at 90°C).

(d) Maker’s instructions should be followed.

During maintenance, routine cleaning and out of service periods

(a) Boilers when not in use should either be kept full of water which is alkaline or

completely empty and dry.

(b) When cleaning: all sludge should be removed, areas mentioned in paragraph 3

above should be thoroughly cleaned by wire brush and scraping and inspected for

pitting and cracks. If any cracks are suspected they must be further investigated by

magnetic crack detection procedure, dye penetrants or any other suitable

methods available.

(c) If any cracking or severe pitting is observed the Department's local Marine

Survey Office should be informed when a passenger ship is concerned. If a cargo

ship is involved the Classification Society should be informed. The repairs must be

effected to the satisfaction of either the Department or the Classification Society.

Department of Transport - Marine Directorate

London WC IV 6LP

January 1990

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LESSONS LEARNED - II

MANAGEMENT CONCERNS

Inadequate Management Support

A serious problem at many boiler plants is the apparent lack of attention

from management and/or lack of communications between operating and

supervisory personnel. This inattention is reflected in numerous ways:

(a) Inaccurate direction or lack of water chemistry knowledge.

(b) Plants operating without assigned first-line supervisors.

(c) Lack of evidence that managers show a physical presence at the plant, or lack

face-to-face communications with operating personnel.

(d) Lack of initial or ongoing training for all levels of managers and operators.

(e) Lack of or inadequate safety program.

(f) Lack of proper maintenance procedures, records, and general order and

appearance of the plant.

Suggested Actions

With budgets under constant scrutiny, support functions such as boiler plant

operations tend to lack a champion, unless the assignment of operations is

delegated to one specific manager – a manager who should have a good

understanding of the operation and has, or takes, the time to monitor operating

performance.

In addition, a training schedule should be established to cover water treatment

and operational training for both managers and operators.

Lack of Effective Maintenance Programs

A ready indication of inadequate maintenance programs is the lack of

documentation of a planned Preventative Maintenance Plan, poor record keeping,

history of downtime, and/or expensive repair costs.

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Suggested Actions

Base management should ensure the assignment of single-point responsibility.

Specific duties would include development and maintenance of:

• A Preventative Maintenance Plan.

• Accurate records of tests and repair activities.

• A training schedule for personnel.

• A safety program.

• A schedule for general housekeeping activities to be followed.

Inadequate Acquisition Processes of Boiler Water Treatment Chemicals and/or

Support Services

High costs of operation, increased repair costs, boiler failures, contract disputes,

terminations and, on occasion, litigation can many times be traced to the

incomplete or inadequate preparation of requests for services.

The selection of a good chemical vendor is very important to plant operations.

Too often the selection is made on the basis of lowest price per pound of vendor

chemicals. What this does is reward the vendor that has the most water in their

chemical products! The competitive selection of chemicals and vendor should be

based on cost to treat 1000 liters of boiler feedwater.

Another factor in buying treatment chemicals is whether to buy chemicals with or

without service. Most of the companies recognized as boiler water treatment

chemical suppliers do not sell chemicals without service. Also, the quality of

service provided varies greatly by company and service representative. Service

includes monthly plant visits, technical assistance and possibly other services.

Conflicts arise because the company may provide advice that results in

unnecessary higher chemical use since the company has an interest in selling more

chemicals.

Typically, chemical products that include service in the purchase price can cost 5

to 20 times more than the generic chemicals.

Pag |80 - 94


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Lack of Effective Safety Programs

Several incidents with employee injuries have occurred in boiler installations.

Common safety problems include simply the lack of a formal safety program, not

maintaining the program through regularly scheduled safety meetings, not

providing back-up for single-shift operators, and lack of safety facilities such

as eye wash basins or shower stalls. Last but not least is the lack of clear, printed

warnings on chemicals used in boiler water treatment.

Suggested Actions

Assign a Safety Coordinator for each facility. Schedule regular safety meetings.

Document ANY safety violations. Conduct regular inspections and training in the

safe use of chemicals and equipment. Develop a standing list of protective

clothing and gear for each work location.

Pag |81 - 94


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OPERATOR PERFORMANCE

Inadequate Control of Oxygen Is a Major Source of Boiler Corrosion

A common maintenance problem for boiler water treatment is a lack of control of

corrosion due to oxygen. Mistakes are made in the mechanical removal of

dissolved oxygen or the chemical scavenging of oxygen or both. This results in

corrosion pitting attack by oxygen on boiler water tubes and feed water lines

which calls for expensive replacement of failed metal and downtime for the boiler.

Suggested Actions

A. Improper Mechanical Removal of Oxygen from Feedwater

Mechanical removal of oxygen is accomplished with a deaerator (DA). The DA

works by heating the water to a boil at which point the solubility of dissolved

oxygen and other dissolved gasses are at their lowest level. The undissolved

gasses are vented to the atmosphere and the deaerated water is used in boiler

feedwater. The little remaining dissolved oxygen should be no more than the

parts per billion range (ppb) which is scavenged by chemical treatment.

Proper DA operation requires a vessel pressure of 3-4 psi above atmospheric and a

water temperature measured at the storage section of 5 °C above the boiling

point for water at the installation’s altitude. There should be a visible 0,4-0,6

meter steam plume coming from the DA’s vent. This contains the unwanted

oxygen and other gasses. Three things to check once per shift is 1.) operating

pressure, 2.) temperature of water in the storage section, and 3.) an 0,4-0,6 meter

steam plume at the DA vent. Oxygen should then be in the 7 to 20 ppb range

depending on the type of DA.

B. Chemical Scavenging of Dissolved Oxygen

The deaerator removes most but not all of the dissolved oxygen. The remainder

must be reacted with oxygen scavengers such as sodium sulfite. Sodium Sulfite is

the most common oxygen scavenger.

A common mistake is to overexpose Sulfite to air so that it is already consumed

before it is applied. This can result from excessive mechanical mixing of Sulfite in

the mix/feed vessel. A mix/feed vessel should also include a floating lid to

minimize its exposure to air. Sulfite and other oxygen scavengers should be fed

into the storage section of the DA -upstream from the boiler. This allows for it

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react with oxygen before the oxygen gets into the boiler and it also helps to

protect feed water lines.

Sulfite should be fed continuously as a function of feed water flow as opposed to

slug dosages. This allows for a proper residual in the operating boiler at all times

and avoids conditions of overtreatment and under treatment swings.

Inadequate Treatment of Carbon Dioxide Is a Major Cause of Condensate

Piping Corrosion and Boiler Deposits

Carbon dioxide comes from the decomposition of the carbonate and bicarbonate

alkalinity that is naturally present in the makeup water. The decomposition occurs

in the boiler and the carbon dioxide that is formed, is volatile enough to escape

with the steam and later condense in the condensate system, forming carbonic

acid which is acidic and corrosive.

The presence of carbon dioxide can be easily determined by measuring the pH of

the condensate. Carbon dioxide lowers the pH. A reading below pH 7.5 indicates

corrosive levels of carbon dioxide.

Suggested Actions

A. Reduce the amount of carbon dioxide produced in the boiler.

One method is to reduce the amount of make-up water used. This is

accomplished by maintaining the optimal cycles of concentration through proper

blow-down and also by recovering as much condensate as possible since

condensate combines with make-up water to form boiler feedwater. Cycles of

concentration, often measured with conductivity or total dissolved solids readings,

should not exceed the point where scaling or carryover occurs. The amount of

condensate returned can be increased by eliminating wasted steam and of course

repairing condensate leaks.

Another method to reduce carbon dioxide is to reduce the amount of alkalinity

(bicarbonate) in the makeup water. Dealkalizers remove alkalinity from the

makeup water which is the precursor of carbon dioxide. This is a form of external

treatment.

B. Carbonic acid can be neutralized using neutralizing amine treatments which are

used to raise the pH to between 7.5 and 8.5.

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The proper amine or blend of amines is dependent upon the length of condensate

piping runs to be protected. Morpholine for example is more effective for short

runs of say 250 meters or less. Diethylaminoethanol (DEAE) is more effective for

runs of up to 1500 meters while cyclohexylamine is more effective for runs over

1500 meters.

Neutralizing amines should be fed directly into the boiler or into feed water

piping. It should not be fed into the deaerator where it can escape via vent piping.

For long and complex condensate systems (over 1600 meters with multiple

locations for steam demands), “satellite” amine feed stations can augment amines

being fed at the boiler plant.

Neutralizing amines should be fed continuously as a function of feed water flow as

opposed to slug dosages. This allows for a proper pH in the condensate system at

all times and minimizes overtreatment and under-treatment swings.

Inadequate Control of Scale and Sludge Impacts Boiler Performance

Scale and sludge can result from mistakes made in: 1) the external treatment to

remove the unwanted scale forming minerals or 2) the internal chemical

treatment or both.

This result in scale and/or sludge that reduces boiler efficiency and even tube

failures which calls for chemical cleaning to remove scale or expensive

replacement of failed boiler tubes.

External treatment (ET) is designed to remove unwanted minerals before they

enter the boiler system i.e. sodium zeolite softeners remove calcium and

magnesium hardness. Problems develop when ET capacity is exceeded allowing

the unwanted minerals to enter the boiler system. The inadequate capacity can

result from improper sizing of ET equipment, excessive makeup water usage,

and/or inadequate regeneration. Often scale/scale damage is a result of poor

monitoring and control of softeners.

The use of improper internal chemical treatment can result in scale and sludge

deposits.

Suggested Actions

Determine the efficiency of external treatment by comparing the design versus

the realized capacity of ET equipment. The design capacity is information supplied

by the manufacturer, but can also simply be calculated based on the size of the

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equipment for resin volume. The run time on a softener is measured by the

amount of water it can soften before regeneration is required. A running log of

softener capacity will show a trend of softener efficiency. As the realized capacity

drops below design capacity, regeneration needs to be performed more often to

prevent excursions of hardness or other unwanted ionic species. Resins may need

replacement or replenishment.

Feed phosphate and dispersant treatments continuously as a function of feed

water as opposed to slug dosages. This allows for a proper residual in the

operating boiler at all times and minimizes overtreatment and under-treatment

swings.

Improper Blow-down is a Major Cause for Scale Formation and Wasted

Scale and sludge can result of insufficient blow-down, even when chemicals are

applied at the desired treatment levels. In a number of cases, blow-down has

been treated as an unrelated procedure to the chemical treatment program,

rather than part of an overall treatment plan. At the same time, excessive blow-

down wastes energy, water, and chemical treatment. The most common problem

is excessive blow-down.

Suggested Actions

Use surface blow-down to control total dissolved solids (TDS) wherever practical.

This is achieved with a manual throttling valve or an automated microprocessor

blow-down controller. It is better to control blow-down continuously or in small

frequent increments rather than infrequent long increments. This avoids wide

swings in the TDS level as well as chemical levels.

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Use bottom blow-down to remove sludge. It is not used to control TDS unless it is

the only blow-down option available. The frequency of bottom blow-down

depends on feed water quality and the type of treatment program being followed.

Boiler load also impacts blow-down requirements. The heavier the load, the more

frequent bottom blow-down is required.

Excessive blow-down is a common problem with boiler operations. The general

attitude is that blow-down will avoid trouble. However, the cost in wasted

energy, water, and chemicals along with the possible replacement of boiler

elements can be significant. Proper blow-down is achieved when adjustments are

made to match boiler load changes, while maintaining the specific control ranges

for TDS, alkalinity, and/or silica.

Inadequate Sampling and Testing Procedures Result in Improper Chemical

Inaccurate gathering and analysis of water samples can result in losing control of

the treatment program. This can lead to a higher cost of chemical treatment,

misapplication of treatment, reduced efficiency, and even boiler failure.

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Chemical test results are only as accurate as the sample collected. Therefore the

sample collected must be truly representative of the system conditions. A poor

sample will yield results that call for unwarranted or insufficient adjustments to

the program.

Suggested Actions

Specific rules apply to good sampling and test procedures:

Sample Point

Boiler samples should be collected at the continuous surface blow-down line using

a sample cooler for operator safety and to prevent flashing (water converting to

steam). If there is no continuous blow-down line then a sample can be collected

from the water column beneath the sight glass which again should be cooled.

Sampling Technique

Sample lines should be flushed thoroughly to minimize contaminants from

stagnant water in the lines. Sample containers should be clean prior to taking a

sample. Containers should be dedicated for sample type i.e. boiler, feedwater,

condensate etc. Heavy duty, high temperature, polypropylene, wide mouth

bottles are recommended over glass. Tests for trace metals like iron and copper

require special preparation. The sample needs to be preserved with acid to bring

the pH down to 2.0 or less. This is necessary to prevent the trace amount of metal

from being absorbed into the walls of the container.

Interval Between Sample Collection and Analysis

For some constituents in boiler water, it is critical that the interval between

sample collection and analysis be as short as possible. Long intervals may allow

some chemicals to continue reacting so that smaller than actual amounts will be

found. An example of this is Sulfite which continues to react with oxygen from the

atmosphere over time. Different constituents in boiler water have different

degrees of stability. Some must be tested immediately after removal: Sulfite,

hydroxide, and pH. Others can last indefinitely when properly contained. The

order of testing should be as follows: 1.) Sulfite, 2.) causticity and pH, and 3.) all

others.

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Poor Records Cause Ineffective Boiler Operations

Well documented logs of water testing results are necessary to indicate the

current status and trends of chemical treatment and general boiler operations.

Records are particularly valuable for preventing boiler failures or determining the

cause of failures that do occur. Well maintained records can predict the condition

of the boiler before inspections are performed.

Suggested Actions

Maintain log records that are organized and easy to read or they are not useable.

Many operations use computer generated spreadsheets and databases that they

create on their own or use from their water treatment service company. Records

worth keeping can include:

Records should be reviewed by supervisory personnel to see if that all parameters

are within specified control limits. If they are consistently out of the control

range, then corrective action is required.

Test results should be periodically verified by an independent testing laboratory to

make sure that accuracy is being achieved.

Inspections Are Invaluable for Boiler Operations

Boiler inspections are necessary to document the effectiveness of the water

treatment program. Proper chemical treatment application and record keeping

can allow one to predict the condition of the boiler, however the inspection

documents the condition. Proper documentation allows for comparison to

previous inspections to see if the condition of the boiler has changed for the

better or worse. Photos and videos should be used wherever practical.

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Suggested Actions

Obtain documents from the previous inspection if applicable, to serve as a

reference for the present condition of the boiler.

Inspect the watersides of the boiler. In many cases the view will be limited

especially for water tube boilers. Fiber optics video inspection equipment is useful

for this purpose. Note the presence or absence of deposits. If present, note the

thickness of the deposit and obtain a sample for laboratory analysis. Good control

of external treatment, chemical treatment, and blow-down will prevent deposits

from forming.

Inspect the watersides for corrosion control effectiveness. The metal should have

a thin layer of magnetite (ferrous-ferric oxide), a self-limiting form of corrosion

that is a protective film. Magnetite has a grayish/brown appearance. Its presence

is indicative of good pH control. The metal should not show any pitting due to

oxygen corrosion attack.

Inspect the mud drum of the boiler. There should be no significant accumulation

of sludge which indicates that adequate bottom blow-down control has been

accomplished.

Safety inspections are above and beyond those described above which are to be

done by operators and must be done by experts in this area.

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9999. WATER CHEMISTRY TERMS. WATER CHEMISTRY TERMS. WATER CHEMISTRY TERMS. WATER CHEMISTRY TERMS

Acid An acid is a substance that furnishes hydrogen ions in an aqueous

solution. It reacts with a pH indicator to give a reading below a pH of 7.0

Algae A simple form of aquatic plant life, which multiply by division and requires

sunlight for survival.

Alkali A chemical compound that furnishes hydroxide ions in an aqueous

solution. It reacts with a pH indicator to give a reading above a pH of 7.0

Analysis The examination of a water sample to determine its chemical

composition and characteristics.

Bacteria A single cell organism without a nucleus, usually in the shape of

rods, spheres, or spirals, and is sub-divided into aerobic bacteria (bacteria which

require oxygen to survive), and anaerobic bacteria (bacteria which survive in the

absence of oxygen).

Biocide A toxic material such as chlorine which is used to kill living bacteria.

Bleed-off A term applied to the portion of re-circulating water that is drawn from

the water system, either continuously or intermittently, in order to de-

concentrate the dissolved and/or suspended solids concentration in water.

Blow-down A term applied to the portion of boiler water that is drawn from the

boiler, either continuously or intermittently, in order to de-concentrate the

dissolved and/or suspended solids concentration in the boiler water, and thus

diminish the potential for scale formation.

Boiler water Boiler water is the liquid phase of steam within a boiler. The term

may also be applied to raw water intended for use in boilers, treated boiler

feedwater, steam condensate being returned to a boiler, or boiler blow-down

being removed from a boiler.

Boiler Water Sample A representative sample of the circulating boiler water.

Buffer A substance that tends to resist changes in the pH of a solution.

Buffer Standard A buffer solution that is used to calibrate pH meters prior to pH

testing.

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Burette A long narrow titrating column that has been accurately calibrated

to indicate the exact volume of liquid dispenses in the test procedure.

Carryover The entrainment of small droplets of boiler water and associated

dissolved solids in the steam leaving the boiler.

Caustic This refers to caustic soda that is sodium hydroxide.

Chlorides Indicates the amount of solids build-up in the water, including salts of

calcium, sodium and potassium. If the Chlorides in the water doubles, all the solids

have doubled.

Chlorine A disinfecting oxidizing agent, which is most widely used in water

treatment.

Chlorine, Combined Available The chlorine residual, which exists in water

systems as a chemical combination with ammonia or organic matter after the

chlorine, has been satisfied.

Chlorine Demand The amount of chlorine consumed by organize matter and

bacteria in water systems.

Chlorine, Free Available The hypochlorous ions (OCI), hypochlorous acid (HOCI),

or any combination thereof present in water (the portion of chlorine in water

systems that is available for the immediate oxidation [killing] of bacteria and

organic matter).

Chlorine, Residual The total amount of free and combined chlorine remaining in

water systems after its chlorine demand has been satisfied.

Chlorine, Total The sum of free and combined chlorine.

Colour Standard A hermetically sealed glass tube containing a stable solution

equivalent in colour to the colour developed when an indicator is added to a

sample solution to determine the concentration of a chemical.

Colourimetric A name, which is given to a chemical test method where the results

of the test are determined by the amount or shade of colour that is developed.

Comparator The device for holding colour standards and a test sample in

adjacent positions so that the colours of each may be easily compared with

one another.

Concentration The amount of a substance per unit volume.

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Conductivity The ability of an aqueous solution to conduct an electrical

current, expressed as micromhos/cm (µS/cm).

Corrosion A process of deterioration where loss of metal occurs due to

chemical reactions at the interface of metal surface and solution.

Corrosion Coupon A pre-weighed metal specimen that is inserted into a liquid

stream in order to determine the corrosiveness of the liquid.

Dealkalized Water A process, which is used for the reduction of alkalinity in

water.

Deaeration The process of removing or drastically reducing the dissolved

gasses (usually oxygen) in water by passing steam upwards through the

water within a closed vessel called a de-aerator.

Demineralized Water Water which has had most of its salts removed by ion

exchange.

Dissolved Oxygen The amount of oxygen dissolved in water.

Endpoint The point in a titration procedure where a colour change in the sample

takes place.

Filtration The separating of a liquid from suspended matter in it by passing the

liquid through a filter paper.

Generic Chemical A chemical, which is identified with a chemical name and not a

proprietary one. It is usually composed of only one chemical.

Halogen The group of elements including chlorine, bromine, and iodine used for

the disinfection of water.

Hard Water Water that has a high calcium or magnesium content.

Hardness, Total The sum of the calcium hardness plus the magnesium hardness

Indicator A chemical reagent added to a test sample to bring about a colour

reaction.

Inhibitor A chemical that interferes with a chemical reaction to reduce or

eliminate corrosion.

Magnesium Hardness The amount of magnesium, which is present in the sample.

MIL (Milliliter or mL) One-thousandth part of a liter (which equals 1 cm3).

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Monitoring The regular sampling, measuring, recording, and/or signaling of the

characteristics of water or waterborne material.

Mpy A measure of corrosion penetration rate expressed as 'mils per year'

mg/L Milligrams per liter, the metric equivalent of parts per million (ppm).

Neutral A water sample is neutral if it has a pH reading of 7.0

ppm Parts per million. A unit of measurement used in chemical testing which

indicates the parts by weight in relation to one million parts of water.

Equivalent to mg/L.

ppb Parts per billion. A unit of measurement used in chemical testing which

indicates the parts by weight in relation to one billion parts of water.

pH This is a scale based on the hydrogen ion concentration by which water

and other substances are measured to determine if they are acid, neutral or

alkaline.

pH Scale Numerical scale used to measure the strength of acids and bases.

Pipette A 'dropper' device that is usually calibrated for measuring small amounts

of liquid.

Precipitate An insoluble compound formed by chemical action between two

or more soluble compounds in solution.

Proprietary Chemical A chemical, which is usually identified with a supplier

specific name and product number. It is usually composed of more than one

chemical.

Reagent A chemical material in liquid, powder or tablet form that has been

especially prepared for use in chemical testing.

Reserve Alkalinity A measure of the buffer capacity of glycol solutions,

determined by titrating the sample with standard hydrochloric acid. The buffer

acts as a corrosion inhibitor in glycol-based heat transfer fluids and the

reserve alkalinity is therefore a measurement of corrosion protection.

Reserve Alkalinity (100%) The reserve alkalinity mathematically converted to 100

vol. % glycol.

Residual The amount or level of an un-reacted material present in the water.

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Scale A hard, crusty deposit that may be found inside boilers, tubes, pipes,

valves, etc.

Shelf Life The length of time that an analytical reagent can be stored

without its chemical composition deteriorating or it undergoing some change that

will make the reagent unacceptable for use.

Shock Treatment The application of extremely high concentrations of chlorine

to destroy bacteria and algae.

Sludge A 'mud-like' residue, which is formed from the chemical treatment of

hardness salts in water, and is considered to be a normal by-product of

water treatment.

Soft Water Water that has a very low calcium and magnesium content.

Soluble A substance, which is easily dissolved.

Standard Solution A solution with a precise known composition.

Suspended Solids Particles within a liquid solution, which can be removed by

filtration.

TDS Total dissolved solids.

Titration A chemical test method using a reagent that is chemically keyed

to the unknown factor being tested. Usually an indicator is added to the

test sample and then the titrating solution is added in measured amounts.

When sufficient titrating solution is added to bring about a colour change in the

sample (the endpoint) the amount of solution added is noted and its volume

multiplied by a standard factor gives the result in ppm of the chemical

compound being measured.

Turbidity A suspension of fine particles that obscures light rays but requires many

days for settling out because of the small particle size.

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Hydrazine N2H4

Sodium Sulfite Na2SO3

Sodium Sulfate Na2SO4

Sodium Chloride NaCl

Trisodium Phosphate Na3PO4

Sodium Hydroxide (Alkali) NaOH

Calcium Carbonate CaCO3

Calcium Sulfate CaSO4

Magnesium Sulfate MgSO4

Silica SiO2

Carbonic Acid H2CO3

Iron Oxides FeO - Fe2O3 - Fe3O4

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