Chapter 1 

INTRODUCTION TO BOILERS A boiler is an enclosed vessel that provides a means for combustion heat to be transferred into water until it becomes heated water or a gas (steam).  The steam or hot water under pressure is then usable for transferring the heat to a process.  Water is a useful and cheap medium for transferring heat to a process.  When water is boiled into steam its volume increases about 1,600 times, producing a force that is almost as explosive as gunpowder.  This causes the boiler to be an extremely dangerous item that must be treated with utmost respect.

 Boilers were used in crude fashions for several centuries but development was slow because construction techniques were crude and the operation was extremely dangerous.  But by the industrial revolution of the mid 1800’s boilers had become the main source of energy to power industrial operations and transportation.  The use of water as a heat transfer medium has many advantages.  Water is relatively cheap, it can be easily controlled, the gas in invisible, odorless, and extremely high purity. The process of heating a liquid until it reaches it's gaseous state is called evaporation.  Heat is transferred from one body to another by means of (1) radiation, which is the transfer of heat from a hot body to a cold body through a conveying medium without physical contact, (2) convection, the transfer of heat by a conveying medium, such as air or water and (3) conduction, transfer of heat by actual physical contact, molecule to molecule.  The heating surface is any part of the boiler metal that has hot gases of combustion on one side and water on the other.   Any part of the boiler metal that actually contributes to making steam is heating surface.  The amount of heating surface a boiler has is expressed in square feet.   The larger the amount of heating surface a boiler has

the more efficient it becomes.  The measurement of the steam produced is generally in pounds of water evaporated to steam per hour. 

Gallons of water evaporated x    8.3 pounds/gallon water  =  Pounds of steam 

In firetube boilers the term boiler horsepower is often used.  A boiler horsepower is 34.5 pounds of steam.  This term was coined by James Watt a Scottish inventor.  The measurement of heat is in British Thermal Units (Btu’s).   A Btu is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.  When water is at 32 oF it is assumed that its heat value is zero.

 

The heat required to change the temperature of a substance is called its sensible heat.  In the teapot illustration to the left the 70 oF water contains 38 Btu’s and by adding 142 Btu’s the water is brought to boiling point.

Sensible Heat 

 In the illustration to the left, to change the liquid (water) to its gaseous state (steam) an additional 970 Btu’s would be required.   This quantity of heat required to change a chemical from the liquid to the gaseous state is called latent heat. The saturation temperature or boiling point is a function of pressure and rises when pressure increases.  When water under pressure is heated its saturation temperature rises above 212 oF. This occurs in the boiler. In the example below the boiler is operating at a pressure of 100 psig which gives a steam temperature of 338 oF or 1185 Btu’s. When heat is added to saturated steam out of contact with liquid, its temperature is said to be superheated.  The temperature of superheated steam, expressed as degrees above saturation, is referred to as the degrees of superheat.  BOILER TYPES:There are virtually infinite numbers of boiler designs but generally they fit into one of two categories: (1) Firetube or as an easy way to remember "fire in tube" boilers, contain long steel tubes through which the hot gasses from a furnace pass and around which the water to be changed to steam circulates, and (2) Watertube or "water in tube" boilers in which the conditions are reversed with the water passing through the tubes and the furnace for the hot gasses is made up of the water tubes.  In a firetube boiler the heat (gasses) from the combustion of the fuel passes through tubes and is transferred to the water which is in a large cylindrical storage area.  Common types of firetube boilers are scotch marine, firebox, HRT or horizontal return tube. Firetube boilers typically have a lower initial cost, are more fuel efficient and

Latent Heat

Firetube Scotch Marine Boiler

easier to operate but they are limited generally to capacities of 50,000pph and pressures of 250 psig.  The more common types of watertube boilers are "D" type, "A" type, "O" type, bent tube, and cast-iron sectional. All firetube boilers and most watertube boilers are packaged boilers in that they can be transported by truck, rail or barge.  Large watertube boilers used in industries with large steam demands and in utilities must be completely assembled and constructed in the field and are called field erected boilers.   

Watertube Boiler D-Type 

Watertube Boiler  "A Type" Watertube Boiler  "O Type"

Miura Watertube Boiler

Field Erected Boiler With Superheater By B&HES at Thomaston, GA 

 Vertical tubeless boilers are used for small loads but really do not fit into either category as they do not have tubes. Boilers and pressure vessels are built under requirements of the American Society of Mechanical Engineers or ASME referred to as the "ASME Code."  High pressure boilers are fired vessels for an operation greater than 15 psig and 160oF and are built in accordance with Section I of the ASME Code with the ASME S stamp.  Vessels with design pressures below 15 psig steam and 180oF hot water are low pressure and are built to Code Section IV.  All unfired vessels are built in accordance with Code Section VIII, Division I and with the ASME U stamp attached.   Repairs to all boilers and pressure vessels are governed by the state boiler jurisdictions which for the US and Canada have universally adopted the National Board of Boiler & Pressure Vessel Inspectors (National Board Code) and affixed with the national board R stamp.  STEAM BOILER SYSTEMS: The feedwater system provides water to the boiler and regulates it automatically to meet the demand for steam.  Valves provide access for maintenance and repair.  The steam system collects and controls the steam produced in the boiler. Steam is directed through piping to the point of use.  Throughout the system steam pressure is regulated using valves and checked with steam pressure gauges.   The steam and feedwater systems share some components.  The fuel system includes all equipment used to provide fuel to generate the necessary heat.  The equipment required in the fuel system depends on the type of fuel used in the system.  All fuels are combustible and dangerous if necessary safety standards are not followed.  Fuels commonly used are nuclear fusion,

electricity, the wastes of certain processes and fossil fuels.  The approximate heat value of certain fossil fuels: 

         Natural Gas 1,000 Btu/Cubic foot          #2 Oil 142,000btu/gallon          #4 oil 148,000btu/gallon          #5 oil 149,000btu/gallon          #6 oil 152,000btu/gallon          Coal 12,500btu/ton          Wood (Dry) 8,000btu/ton          Wood (Wet) 4,000btu/ton  

In a fuel oil fired boiler plant, fuel oil leaves the tank through a suction line and duplex strainer traveling then to the fuel oil pump.  The fuel oil is then forced through the pump and then through the discharge line.  From the discharge line some fuel oil is burned and some returned to the tank through a regulating valve.  In a natural gas fired plant gas is supplied at a set pressure which varies depending on the gas source.  Gas systems are low pressure or high pressure.  In a low pressure gas system city gas pressure is reduced from pounds to inches of pressure by passing through a gas regulator.  Through the regulator gas is drawn into the burner and mixed with air supplied by a blower.  This mixture is directed to the burner where it is ignited with the pilot light.  In a high gas pressure system, gas passes through the regulator and gas is reduced to the proper pressure for the burner.  Some boilers have combination burners which can burn gas or fuel oil or a combination of both gas and fuel oil.  Coal fired boilers use mechanical feeders or stokers to feed fuel to the burner at a consistent rate.  For example, in a chain grate stoker coal is fed through the hopper and regulated before passing under the ignition arch.   The coal continues on a conveyor which carries the ignited coal slowly under the heating surface. Ash, slag and unburned parts or clinkers are discharged at the other side of the conveyor. The draft system regulates the flow of air to and from the burner.  For fuel to burn efficiently the right amount of oxygen must be provided.   Air must also be provided to direct the flow of air through the furnace to direct the gases of combustion out of the furnace to the breaching.  A forced draft system uses a fan to force (or push) air through the furnace.  An induced draft system uses a fan to draw (or pull) air through the furnace.  A combination or balanced draft system uses forced and induced draft fans.   Gases of combustion enter the stack from the breaching and are released to the atmosphere. COMBUSTION:Is the method of combining the fuel and air systems in a source of heat at sufficient temperature to produce steam.  Combustion may be defined as the

rapid chemical combination of oxygen with the combustible elements of a fuel.  Only three combustible, chemical elements are of any significance: carbon, hydrogen and sulfur.  The boiler combustion furnace in which the fuel burns provides a chamber in which the combustion reaction can be isolated and confined so that it can be controlled.  In a scotch marine boiler it is referred to as a Morrison tube or in other boilers the firebox area.  The convection surfaces are the areas to which the heat travels that is not transferred in the combustion furnace.  Here additional heat is removed.  The burner is the principal device for the firing of oil and/or gas.   Burners are normally located in the vertical walls of the furnace.  Burners along with the furnaces in which they are installed, are designed to burn the fuel properly. STEAM TO WATER CYCLE:In a steam heating system steam leaves the main steam line and enters the main steam header.  From the main header piping directs the steam to branch lines.  Branch lines feed steam through a riser to the steam heating equipment.  At the heating equipment heat is transferred to the building space.   As the steam releases heat to the building space and is cools it turns back to water or condensate.  The condensate is separated from the steam by a steam trap. The steam trap allows condensate to pass but not the steam.  The condensate passes through the condensate return line and is collected and directed back to the boiler to repeat the steam to water process.  Referring back to the teapot example, after repeated use it began to acquire a "buildup" of solids from the water.  The same separation of solids in the water occurs in the boiler but since it is operating continuously and at higher temperatures this "buildup" can occur very rapidly.   When this occurs the heat transfer can not be achieved as readily which requires more fuel to produce the steam. If continued unchecked damage to the metals in the boiler shell and tubes will result. Pretreatment equipment such as softeners, de-mineralizes, etc. are used to remove as much of the dissolved solids as possible before they get to the boiler.  To remove the solids that continue to the boiler chemicals are added to react with the solids creating a sludge.  This sludge is then periodically removed by opening valves from the bottom of the boiler and relieving it to the drain.  This process is called blowdown. Waterside problems can also shorten boiler life from corrosion brought on by the oxygen content in the feedwater.  Pretreatment for the removal of oxygen is performed in a deaerator but here again the removal is not complete and chemical additions are made to aid in improving the oxygen removal process. The water supplied to the boiler that is converted into steam is called feedwater.  The two sources of feedwater are: (1) Condensate. or condensed steam returned from the processes and (2) Makeup water (usually city water) which

must come from outside the boiler room and plant processes.  For higher boiler efficiencies the feedwater can be heated, usually by economizers.

Chapter 2

MAKEUP WATERA.   WATER SOFTENERS: Water as it passes over the ground, through caves and springs picks up some of the elements from the limestone and other elements of nature which dissolved and remain.  These elements collectively are called hardness.  Grandma's tea kettle, used as an example in Chapter One, always seemed to have a "build up" in the bottom which she removed periodically usually with vinegar.  This "build up" is called hardness. In a heavy use industrial steam boiler the water is could be completely replaced as often as once each hour.  Obviously at higher turnover, temperatures and pressures than the tea kettle the boiler would quickly have scale from this hardness that would reduce and ultimately prevent water circulation and heat transfer which will destroy the boiler.  The higher the operating pressure of the boiler the more critical the removal of foreign items from the feedwater becomes.  Large utility boilers operating at 3,000 psig + may actually use distilled water for ultimate purity.

The purpose of a water softener is primarily for the removal of hardness from the boiler makeup water.  Makeup water is the water supplied from the municipal water system, well water, or other source for the addition of new water to the boiler system necessary to replace the water evaporated.  Some filtering of the water may occur in the water softener but that is not the purpose of its design and too much of other pollutants in the water could actually foul the water softener affecting its operation.  Hardness is composed primarily of calcium (Ca) and magnesium (Mg) but also to lesser amounts sodium (Na), potassium (P), and several other metals.  Hardness is measured in grains with one grain of hardness in the water being 17.1 ppm of these elements.  The purpose of using hardness as the unit of measure is that tests to measure in parts per million (ppm) are much more difficult and expensive to use. Hardness varies from area to area.  Usually near salt water the hardness is very low as the limestone is virtually non existent and in mountainous areas where limestone is everywhere hardness is usually very high.

All softeners soften or remove the hardness from the water.  The primary minerals in the water that make "hard" water are Calcium (Ca++) and Magnesium (Mg++).  They form a curd with soap and scale in piping, water heaters and whatever the hard water contacts.  Hardness is removed from the water by a process known as positive ion exchange.  This process could also be known as "ion substitution", for substitution is what occurs.  Sodium (Na+) ions, which are "soft" are substituted or exchanged for the Calcium and Magnesium as the water passes through the softener tank.

The softening media is commonly called resin or Zeolite.  The proper name for it is polystyrene resin. The resin has the ability to attract positive charges to itself.  The reason it does so is because in its manufacture it inherits a negative charge.  It is a law of nature that opposite charges attract, i.e., a negative will attract a positive and vice versa.  A softener tank contains hundreds of thousands of Zeolite beads.  Each bead is a negative in nature and can be charged or regenerated with positive ions. In a softener, the Zeolite is charged with positive, "soft" sodium ions.

As "hard" water passes through the Zeolite, the Calcium and Magnesium ions are strongly attracted to the beads.  As the "hard" ions attach to the Zeolite bead, they displace the "soft" Sodium ions that are already attached to the bead.  In effect, the Sodium is "exchanged" for the Calcium and Magnesium in the water supply with the Calcium and Magnesium remaining on the Zeolite beads and the Sodium ions taking their place in the water flowing through the softener tank. The result of this "exchange" process is soft water flowing out of the tank.

It can now be readily understood that a softener will continue to produce "soft" water only as long as there are Sodium ions remaining on the Zeolite beads to "exchange" with the Calcium and Magnesium ions in the "hard" water.  When the supply of Sodium ions has been depleted, the Zeolite beads must be "regenerated" with a new supply of Sodium ions.  The regeneration of the Zeolite beads is accomplished by a three step process. SOFTENER DESIGN:Water softeners come as single mineral tank units (simplex), double mineral tank units (duplex) and multiple mineral tank units.  Since regeneration cycles can take approximately one hour simplex units are used only when this interruption can be tolerated.  To avoid interruption duplex units are used so that the regeneration of one unit can be accomplished while the second unit is on line.  Triplex or other multiplex units usually are the result of need for increased capacity and units can be added to keep soft water available.  The reliability of new electronic metering/controls for regeneration have allowed users to depend on smaller units with more frequent regeneration.

Simplex Softener Duplex Softener Triplex Softener 

REGENERATION PROCESSBACKWASH:The flow of water through the mineral bed is reversed.  The mineral bed is loosened and accumulated sediment is washed to the drain by the upward flow of the water.  An automatic backwash flow controller maintains the proper flow rate to prevent the loss of resin. BRINE DRAW AND SLOW RINSE:Ordinary salt has the capability to restore the exchange capacity of the mineral.  A given amount of salt-brine is rinsed slowly through the mineral bed. After the salt-brine is drawn, the unit will continue to rinse slowly with water to remove all of the salt-brine from the media bed. FAST RINSE:A high down flow of water repacks the mineral bed.  Any trace of brine not removed in slow rinse is flushed to the drain.The unit is then returned to SERVICE the brine maker is refilled with fresh water to form salt brine for the next regeneration.  The total regeneration time is approximately 60-90 minutes. SOFTENER SIZING FORMULA:                         C = M * T * H /RC  =   Capacity of softener in cubic feet of resinM  =  Makeup water volume per hour in gallons; the volume needed to be softened (8.34 pounds per gallon)T  =  Time in hours desired between regeneration cyclesH =  Hardness of water in grains (17.1 ppm per grain hardness)R =  Resin Capacity per cubic foot (this is virtually always 30,000 grains) 

Chapter 3

BOILER FEEDWATERA.   DEAERATION:  All natural waters contain dissolved gases in solution.  Certain gases, such as carbon dioxide and oxygen, greatly increase corrosivity.  When heated in boiler systems, Carbon dioxide (CO2) and oxygen (O2) are released as gases and combine with water (H2O) to form carbonic acid, (H2CO3).                                        CO2 + O2 + H2O      >        H2CO3

Removal of oxygen, carbon dioxide and other non-condensable gases from boiler feedwater is vital to boiler equipment longevity as well as safety of operation.  Carbonic acid corrodes metal reducing the life of equipment and piping.  It also dissolves iron (Fe) which when returned to the boiler precipitates and causes scaling on the boiler and tubes.  This scale not only contributes to reducing the life of the equipment but also increases the amount of energy needed to achieve heat transfer.  This is discussed in more detail in Chapter 5 The term given to the mechanical removal of dissolved gases is deaeration.  Mechanical deaeration for the removal of these dissolved gases is typically utilized prior to the addition of chemical oxygen scavengers.  Mechanical deaeration is based on Charles' and Henry's laws of physics.  Simplified, these laws state that removal of oxygen and carbon dioxide can be accomplished by heating the boiler feedwater which reduces the concentration of oxygen and carbon dioxide in the atmosphere surrounding the feedwater.

The easiest way to deaerate is to force steam into the feedwater, this action is called scrubbing.  Scrubbing raises the water temperature causing the release of O2 and CO2 gases that are then vented from the system.  In boiler systems, steam is used to "scrub" the feedwater as (1) steam is essentially devoid of O2

and CO2, (2) steam is readily available and (3) steam adds the heat required to complete the reaction.  For efficient operation, deaerating equipment must satisfy the following requirements: (1) Heating of the feedwater:  The operating temperature in the unit should be the boiling point of water at the measured pressure.  The pressure/temperature relationship is important since boiling must take place rapidly for quick and efficient removal of gases. If this temperature and pressure cannot be economically achieved then it is important to get as close to it as possible.  (2) Agitation decreases the time and heat energy necessary to remove dissolved gases from the water.  (3) Maximization of surface area by finely dispersing the water to expose maximum surface area to the steam.  This enables the water to be heated to saturation temperature quicker and reduces the distance the gases have to travel to be liberated.  (4) The liberated gases must be vented to allow their escape from the system as they are released.

While the most efficient mechanical deaerators reduce oxygen to very low levels (.005cc/l or 5 ppb), even trace amounts of oxygen may cause corrosion damage to a system.  Consequently, good operating practice requires removal of that trace oxygen with a chemical oxygen scavenger such as sodium sulfite or hydrazine.  Free carbon dioxide can be removed by deaeration, but this process releases only small amounts of combined carbon dioxide.  The majority of the combined carbon dioxide is removed with the steam of the boiler, subsequently dissolving in the condensate, frequently causing corrosion problems.  These problems can be controlled through the use of volatile neutralizing amines or filming amines.

TYPES OF MECHANICAL DEAERATORS:1.  Tray Type Deaerators are composed of a deaerating section and a feedwater storage section.  Incoming water is sprayed through a perforated distribution pipe into a steam atmosphere where it is atomized.  There it is heated to within a few degrees of the saturation temperature of the steam.  Most of the non-condensable gases are released to the steam as the water enters the unit.  The water then cascades through the tray section, breaking into fine droplets, which immediately contact incoming steam.  The steam heats the water to the saturation temperature of the steam and removes all but a trace of oxygen.  Deaerated water falls to the feedwater storage section below and is protected from recontamination by a blanket of steam.  As the non-condensable gases are liberated, they as well as a small amount of steam are vented to atmosphere.  It is essential that sufficient venting is provided at all times or deaeration will be incomplete.

 2.  Spray Type Deaerators work on the same general principle as the tray types.  The spray-type deaerators do not use trays for dispersion of the water.  In this case, spring loaded nozzles located in the top of the unit spray water into a steam atmosphere which is heated to within a few degrees of the saturation

temperature of the steam.  Most of the non-condensable gases are released to the steam, and the heated water falls to a water seal and drains to the lowest section of the steam scrubber.

The water is scrubbed by large quantities of steam and heated to the saturation temperature prevailing at this point.  The intimate steam to water contact achieved in the scrubber efficiently strips the water of dissolved gases.  As the steam-water mixture rises in the scrubber, a slight pressure loss causes the deaerated water temperature to remain a few degrees below the inlet steam saturation temperature.  The deaerated water overflows from the steam scrubber to the storage section below.

The steam, after flowing through the scrubber, passes up into the spray heater section to heat the incoming water.  Most of the steam condenses in the spray section to become part of the deaerated water.  A small portion of the steam, vented to atmosphere, removes non-condensable gases from the system.

3.  Spray/Tray Type Deaerators are a combination of the above with a steam spray nozzle sending the water over the trays.

4.   Feedwater Tanks are another form of mechanical deaerators normally found in small firetube and watertube boiler systems due to cost considerations.  These less expensive systems are limited by design as they are operated at atmospheric pressure with feedwater temperatures ranging from 1800F - 2120F; while deaerators operate under pressure allowing for higher temperatures and more efficient oxygen removal.

Like deaerators, feedwater tanks operate by forcing steam into the feedwater which scrubs oxygen and carbon dioxide gases that are then vented to atmosphere.

Steam enters the bottom of the tank agitating the feedwater as it rises to the top of the tank, and finally is vented along with the liberated gases.  The temperature is normally controlled as high as possible without causing pump problems which occurs when the Net Positive Suction Head (NPSH) is too low.  Steam bubbles form and fill the pump cavity causing vibration, a condition know as cavitation.  This condition may cause serious damage to the feedwater pump and jeopardize steam production.  The most practical potential solution for cavitation is the installation of a slipstream, which allows a portion of the high pressure feedwater to recirculate to the suction side of the pump where it lowers the temperature and eliminates the boiling and cavitation.  The slipstream will not always work leaving the choices of increasing the NPSH by increasing the distance between the tank and the pump, or sizing a new pump properly. Practically speaking, most feedwater tanks are controlled between 1800F - 2000F and rely more on the assistance of a chemical oxygen scavenger for complete oxygen removal.  Pressurized deaerators must have the ASME U  stamp attached and be built under the regulations of The American Society of Mechanical Engineers Section VIII, Division I. 

B.   ECONOMIZER : An economizer removes additional Btu’s from the stack gasses by circulating the deaerated boiler feedwater through a series of bent tubes in the stack.  This translates into a "free" source of energy from the boiler operation.  Finned tube economizers are less costly and more efficient as the "fins" are a source of heat transfer as well as the tubes.  Economizers in watertube boilers typically increase the efficiency of the boiler 4-10% which is usually less than a one year payback.  Due to the higher efficiencies of firetube boilers the payback is usually longer and therefore economizers are not used as frequently on them.  An economizer can also be a useful means of increasing the steam capacity of a boiler.

 The use of high sulfur oils, particularly #6 oil, is very corrosive on the economizer tubes.  This can be improved by increasing the temperature of the feedwater to the economizer and the use of soot blowers but the life of an economizer in that environment is limited to about 2-3 years.  A bare tube economizer is easier to keep free of the corrosive sulfur but requires more tubes to achieve the same efficiency as a finned tube economizer.  Since the economizer is directly part of the boiler and has contact from the gases of combustion it must also be built under the regulations of The American Society of Mechanical Engineers Code Section I and have the ASME S stamp attached.

Chapter 4 

BOILER WATER CHEMISTRY 

Producing quality steam on demand is the purpose of operating industrial boiler systems.  Achieving that goal depends on properly managed water treatment to control steam purity, deposits and corrosion.  A boiler is the sump of the boiler system.  It ultimately receives all of the pre-boiler contaminants.  Boiler performance, efficiency, and service life are direct products of selecting and controlling the chemistry used in the boiler.

Boiler Operation Costs The boiler water must be sufficiently free of deposit forming solids to allow rapid and efficient heat transfer and it must not be corrosive to the boiler metal.  Deposits and corrosion result in efficiency losses and may cause boiler tube failures and inability to produce steam.  The predominant cost factor for producing steam is fuel costs, as shown below.  

 DEPOSIT CONTROL:Deposits in boilers may result from hardness contamination of feedwater, and corrosion products from the condensate and feedwater system.  Hardness contamination of the feedwater may result from either deficient softener systems or raw water in leakage of the condensate.  Deposits act as insulators and slow heat transfer.  The insulating effect of deposits cause the boiler metal temperature to rise and may lead to tube-failure by overheating.  Large amounts of deposits throughout the boiler could reduce the heat transfer enough to reduce the boiler efficiency.  The graph demonstrates that different types of deposits will effect boiler efficiency differently.  This is why it is important to have an analysis of deposit characteristics.

 When feedwater enters the boiler, the elevated temperatures and pressures cause the components of water to take on dramatic changes.  Most of the components in the feedwater are soluble; they are dissolved in the water.  However, under heat and pressure most of the soluble components come-out of solution as particulate solids, sometimes in crystallized forms and other times as amorphous particles.  The coming-out of solution is referred to as retrograde solubility, and means that as temperature increases, ability to stay in solution decreases.  When solubility of a specific component in water is exceeded, scale or deposits develop. Internal chemical treatment for deposit control is achieved either by adding a treatment to prevent the contaminants from depositing or by adding a treatment chemical that will allow for easy removal by blowdown.  Hardness can be kept from depositing in boiler water by treatment with chelating agents. When phosphate treatment is preferred over chelant treatment, the boiler water is conditioned to form a fluid sludge which can be removed by bottom blowdown.  Formation of this sludge requires that alkalinity from caustic be present in the boiler water.  If sufficient alkalinity is not maintained in the boiler water, a sticky precipitate will form and reduce heat transfer.  Even when the precipitates formed in the boiler water are in the form most desired, they are often difficult to remove completely by blowdown.  This is especially true when the precipitates also contain iron and copper corrosion products from the preboiler system and organic contaminants from condensate returns.  Sludge conditioners enhance the removal of precipitates from industrial boilers.  Sludge conditioners are organic polymers which combine with the precipitates to permit the particles to be dispersed.  This makes removal by blowdown easier. CONVENTIONAL PHOSPHATE TREATMENT:Conventional phosphate control involves maintaining a phosphate residual and a hydroxide alkalinity residual in the boiler water.  Phosphate residuals are typically maintained in the range of 20-40 ppm PO4.  Hydroxide alkalinity, if controllable

without excess blowdown, are maintained in the range of 300 -500 ppm OH. This treatment provides the ideal conditions for formation of calcium and magnesium precipitates in the preferred states.  It also provides a residual of alkalinity to neutralize any acid contamination, such as organic acids.  It may, however, promote foaming, especially if organic contaminants enter the boiler.  CHELANT TREATMENT:A chelant is a compound which is capable of "grabbing onto" calcium, magnesium and iron.  Chelant treatment of boiler water is attractive because the chelates of calcium and magnesium are soluble.   The undesirable scales of calcium carbonate and calcium sulfate are successfully eliminated by chelant treatment.  While the chelates of the hardness and iron contaminants are soluble, some chemistry precautions need to be mentioned.  Phosphate will compete with the chelant for calcium, and if present in significant amounts, will result in undesirable calcium-phosphate deposits.  Phosphate can enter the boiler water where city water makeup supplies phosphate.  Both hydroxide alkalinity and silica compete with the chelant for magnesium.  Depending on the concentration of all the boiler water chemistry, magnesium silicate deposits may result.  Chelants should be fed to the feedwater downstream of any copper alloys, after the deaerator and before the boiler drum.  The preferred feed location is down-stream of the boiler feedwater pump.  A stainless steel injection quill is required.

 Feed to the deaerator storage is not recommended since copper alloys in the boiler feed pump may be attacked.  Proper feed of chelant will result in a chelant residual in the boiler water.  The photo below shows the preferred feed locations for chelant feed and other requirements for adequate assurance of chelant control. 

 

Injection Quill

1. Feed chelant products continuously to boiler feedwater line, preferably after the economizer.

2. Use a 304 SS injection quill. 3. Use a 316 SS chemical feed

line. (If not possible, ensure that 316 SS is used at least three feet prior to the injection quill).

4. Feed chelant only downstream from copper or copper alloys.

5. Feed catalyzed sulfite or a suitable oxygen scavenger to the storage section of the deaerating heater.

6. Assure that the feedwater mixes with boiler water before entering downcomer tubes.

7. Maintain feedwater pH >8.0  A chelant residual in the boiler water, however, is not in itself proof of adequate feed control.  A chelant residual should be maintained in the feedwater at all times.  Chelant treatment is not a solution for highly variable and excessive concentrations of hardness in the makeup and condensate returns.

Chapter 5

CONDENSATE RETURN SYSTEMWhen steam has performed its work in manufacturing processes, turbines, building heat, etc. it transfers heat and reverts back to a liquid phase called steam condensate.  However, not all the energy used in producing steam is lost when condensate is formed.  As most condensate return is still relatively hot (130OF to 225OF) , it is very valuable as a source of feedwater.   There is a significant fuel savings related to the heat required to raise the temperature of makeup water at (50OF to 60OF) to equal that of the return condensate, not to mention the additional cost in pretreating (softening) the makeup, as well as basic water cost itself.

When pure water H2O is used to produce steam, then its condensate is also pure H2O however, as we have learned the water we use to produce steam is not pure containing many dissolved minerals and gases. The heat and pressure of the boiler break down the alkalinity in the boiler water to form carbon dioxide gas CO2. Leaving the boiler with the steam it travels throughout the plant supply system. When the steam condenses, the carbon dioxide dissolves in it to form carbonic acid. This reaction is chemically expressed as:

H2O + CO2  =   H2CO3

This acid depresses the condensates pH and causes corrosion to take place.  This corrosion appears as grooving or gouging in the bottom of steam headers or condensate return lines.  Most often it weakens pipe walls at threaded joints and the resultant metal loss can lead to large amounts of copper and/or iron being returned to the boiler to cause troublesome deposits.  Oxygen, as in the boiler system, can cause localized attack in the form of pitting when present in the condensate system.  This type of corrosion can generally cause equipment to fail more quickly than the generalized corrosion caused by carbonic acid attack due to it concentrating in a small area. Oxygen can infiltrate the system from open condensate receivers, poor deaeration or leaky siphons.

There are three main chemical programs to control corrosion in the condensate system, being neutralizing amines, filming amines and contamination neutralizing and filming amines.

NEUTRALIZING AMINES are high pH materials which neutralize the carbonic acid formed in condensate systems. By raising and controlling pH level in condensate from 7.5 to 9.0, neutralizing amines retard acid attack and greatly reduce the amount of corrosion products entering the boiler.

The three primary neutralizing amines in use today are: 1. Morpholine - a low distribution ratio product. 2. Diethyleminoethanal (DEAE) - a medium distribution ratio product. 3. Cyclohexylamine - a high distribution ratio product.

 The distribution ratio is used to predict the amine concentration in the steam and condensate phases and impacts significantly regarding proper amine selection.

Distribution Ratio = Amine in Steam Phase   /  Amine in Condensate Phase

Neutralizing amines have low flashpoints and therefore can be fed directly to the feedwater or boiler water, or they can be fed directly into the steam header. The feed rate is based on the amount of alkalinity present in the feedwater. Neutralizing amines offer excellent protection against carbonic acid attack, but little protection against oxygen attack.

FILMING AMINES are various chemicals that lay down a vary thin protective barrier on the condensate piping protecting it against both oxygen and carbonic acid attack. The protective film barrier is not unlike the protection afforded an automobile by an application of car wax.

The protective film barrier is continuously being removed (a little at a time), requiring continuous feeding of the filming amine based on steam flow rather than feedwater alkalinity. Care must be taken to start this program slowly with an initial feedrate of one fifth that of the final feedrate to prevent the removal of old corrosion products from the system and their subsequent return to the boiler. Additionally, the filming amine should be fed using an injection quill to the steam header to insure proper vaporization and distribution throughout the steam system.

The formation of gunk balls (Gunking) can occur due to overfeed, contaminants in the condensate or wide pH swings causing deposits to form in low flow areas like steam traps.

COMBINATION NEUTRALIZING AND FILMING AMINES are the combination of neutralizing and filming amines and are a successful alternative to protect against both carbonic acid attack and oxygen attack. As its name implies, it combines the elevated pH approach to neutralize carbonic acid in conjunction with the protective barrier film approach. are the combination of neutralizing and filming amines and are a successful alternative to protect against both carbonic acid attack and oxygen attack. As its name implies, it combines the elevated pH approach to neutralize carbonic acid in conjunction with the protective barrier film approach.  The neutralizing amines, although they will elevate pH, main purpose is to provide better distribution of the filming amine throughout the condensate system which in turn helps to prevent gunking. As with filming amines they should be fed directly to the steam header utilizing an injection quill.

SUMMARY.  Clearly each program or approach has certain features and benefits as well as limitations. Each different set of operating conditions will tend to dictate the appropriate treatment that is required. The expected steam pressure, temperature, system metallurgy and the plants systems pH level all play an important role in determining the most effective treatment program. Clearly each program or approach has certain features and benefits as well as limitations. Each different set of operating conditions will tend to dictate the appropriate treatment that is required. The expected steam pressure, temperature, system metallurgy and the plant systems pH level all play an important role in determining the most effective treatment program.

Chapter 6

COMBUSTION & CONTROLSCombustion is the rapid chemical combination of oxygen (O2) with the combustible elements of a fuel that results in the release of heat.  Air is the source of oxygen for boilers.  Fossil fuels such as natural gas, oil and coal, biomass and electricity are primary types of boiler fuel.  The primary elements in the fuel, significant to combustion, are carbon (C), hydrogen (H), nitrogen (N) and sulfur (S); these are called hydrocarbons.  

10 Air (O2) + 1 Gas     =     CO2 + 2H2O + 8N2 + Heat

The objective of good combustion is to release all of the heat in the fuel.  This is accomplished by controlling the "three T's" of combustion which are (1)  temperature high enough to ignite and maintain ignition of the fuel, (2) turbulence or mixing of the fuel and oxygen, and (3) time sufficient for complete combustion.   Not all of the Btu's in the fuel are converted to heat and absorbed by the steam generation equipment.   Usually all of the hydrogen in the fuel is burned and most boiler fuels, allowable with today's air pollution standards, contain little or no sulfur.  So the main challenge in combustion efficiency is directed toward unburned carbon (in the ash or incompletely burned gas) which forms CO instead of CO2.

The burner is the principal device for the firing of the fuel.   Burners are normally located in the vertical walls of the furnace.  Burners, along with the furnaces in which they are installed, are designed to burn the fuel properly by making the proper combination of the "three T's."  Combustion controls assist the burner in regulation of fuel supply, air supply, (fuel to air ratio), and removal of gases of combustion to achieve optimum boiler efficiency.  The amount of fuel supplied to the burner must be in proportion to the steam pressure and the quantity of steam required.  The combustion controls are also necessary as safety devices insuring the boiler not only operates but operates safely.

A drop in steam pressure necessitates an increase in the fuel supplied to the burner.  Conversely, an increase in steam pressure necessitates a decrease in the fuel supplied.  Any change in the amount of fuel supplied requires a corresponding change in the air for combustion supplied to the burner.

To maintain high combustion efficiency, the air to fuel ratio must be balanced from the lowest firing rate to the highest firing rate.  If there is an imbalance in the air to fuel ratio, smoking, flame failure, wasted fuel and in extreme cases an explosion could result.

Combustion controls also regulate the removal of gases of combustion by maintaining a consistent furnace pressure throughout different firing rates.  By maintaining a consistent firing rate, combustion  controls improve regulation of feedwater and superheat temperature.  A consistent firing rate reduces fluctuation of the boiler water level and increases the life of the boiler drum and tubes.

The programmer is the mastermind that controls the starting sequence and firing cycle of a burner.  The programmer controls the operation sequence of the blower, burner motor, ignition system, fuel valve, and all other components of the ON/OFF control system.  The programmer also provides a suitable purge period before ignition and after burner shutdown when explosive combustibles are removed.  The programmer is designed to deenergize all fuel valves within 4 seconds after loss of the flame signal.  In addition, the programmer automatically restarts a new cycle each time the pressure control closes or after a power failure, but locks out and must be reset manually after any flame failure.  A burner must always start in low fire and shut down in low fire which prevents wasting fuel and reduces the possibility of a flareback when excess fuel accumulates in the furnace.  

The pressure control (pictured right) regulates the operating range of the boiler by modulating the burner on boiler steam pressure demand.  The pressure control is installed using a siphon to protect the bellows from the high temperature of steam.  The pressure control sends signals to the modulating motors.   Modulating motors (pictured left) use conventional mechanical linkage or electric valves to regulate the primary air, secondary air, and fuel supplied to the burner.  The modulating pressure control is installed using a siphon to protect the bellows from the high temperature of steam.

The boiler water level control is a safety feature which will shut the boiler off if the water level drops to an unacceptable level.  Boilers have two water level controllers as a safety feature in case one fails.  The two level controllers are also set at different levels with the controller at the higher level sounding an alarm and the controller at the lower level actually shutting down the boiler.  The boiler governing codes require the reset of the boiler to be done manually by an operator for safety and not automatically.  Boiler level controls may be a float type as pictured at right or a probe type which operates by testing for conductivity to determine if the water level is adequate.

The Control firing sequence occurs at cold startup or when the steam pressure drops, the pressure control completes an electric circuit, which starts a timer motor cam turning in the programmer.  The first contact on the timer motor cam closes and starts the burner motor that rotates the primary air fan.  The primary air fan blows air into the furnace to purge any unburned fuel present in a gaseous condition.  This process in called prepurging the furnace.  By prepurging the furnace before pilot ignition, the danger of a furnace explosion is reduced.  Depending upon the size of the furnace the purge cycle takes approximately 30 seconds but may take as long as 60 seconds.  The programmer is still operating and when the second contact closes, the circuit of the ignition transformer is completed.  This causes a spark in front of the gas pilot tube.  At the same time, a solenoid valve is opened in the gas pilot line, allowing gas to flow through the gas pilot tube and be ignited by the spark.  The scanner is located on the front of the boiler and is used to sight the pilot.  Sighting the pilot through the scanner will verify that the pilot is lit.  This process is referred to as proving pilot.   The next step is to close the contact which completes the circuit to the main fuel valve, which opens only after the scanner has proved pilot.  With the main fuel valve open the fuel enters the furnace and is ignited by the pilot.  The scanner is then used to prove the main flame.  The programmer continues to operate for a few more seconds, securing circuits to the ignition transformer and the gas pilot.  After the circuits are secured, the programmer stops.  The burner is now regulated by the pressure control and the modulating pressure control.  If the scanner senses a flame failure, the system is purged and secured.  The programmer is then manually reset to the start cycle.

Chapter 6B

MONTHLY BOILER MECHANICAL SAFETY CHECKS

The monthly safety check on combustion and mechanics is just as important an important a part of the overall boiler program as the water treatment service.  Boiler users have long seen the value of proper water treatment as vital to the success of an effective boiler maintenance program. For a long time the mechanical needs of boilers have only been addressed when there was a problem or when a shutdown occurred. The seven advantages of this preventative maintenance program: (1) reducing fuel cost by improving efficiency, (2) omitting the increasing capital costs of major boiler repairs or replacement, (3) reduced downtime due to unexpected breakdowns, (4) improved safety, (5) operator training , (6) third party audit, and (7) insurance assurance. (1) Reducing fuel costs was not important for many years.  It was not a significant part of overall manufacturing, operating costs.  However, the Arab oil embargo in the 1970's forever changed that view.  Some industries found that energy was their second highest cost falling close to their number one cost of labor. At present we have an increase in competition resulting from the deregulation of natural gas.  Businesses are very conscious about energy efficiency.  Energy efficiency is vital in an industry to remain competitive.  And the long range planning of the American industry is to preserve energy supplies for the future.   A boiler with a 20,000PPH load and seven day week operation will use $1,000,000 of natural gas per year.  At today's price of $5.00 per mcf of natural gas fuel savings alone will pay for the monthly maintenance service.  With only a 1% improvement in efficiency the annual savings add up to $10.000.  Several boiler companies are selling visual inspections as a low cost alternative but visual inspections alone accomplish little or nothing and have no cost benefit.  A combustion analyzer with stack probe and printout is recommended.  To obtain a computer analysis of your boiler fuel efficiency and operating data contact your B&HES technical representative. (2) Capital costs associated with the purchase of new boilers have risen dramatically in the past decade. But this has been for the good.  Safety requirements of CSD1 (Control Safety Device) and NFPA (National Fire Protection Agency) have now been adopted by virtually all the states and will

contribute greatly to the safety of boilers in the future.  Control systems are now more sophisticated for better load management and DCS (distributive control systems) allow for connecting to computer controllers.  The knowledge of our qualified service technicians today is much greater than five years ago.  Other boiler companies have failed to keep up with the rapid change in technology.  Proper mechanical service will reduce repair and capital costs. (3) Downtime is one of the most expensive items associated with improper maintenance of mechanical equipment.  Outages can cost from thousands of dollars per hour in a small plant to hundreds of thousands of dollars in a large plant.  Monthly mechanical testing often results in early detection of improper functioning controls.  If possible we replace them at  that time.  B&HES service vehicles typically carry over $ 10,000 in inventories.  In the least case replacement can be made at the customer's next scheduled down time.  In a typical boiler room situation, the service program pays for itself when it prevents just one shutdown per year. (4) Safety The lack of safety can easily become the most expensive cost of the boiler operation.  A rare waterside explosion occurred in Chattanooga several years ago on New Years night with temperatures at 0oF.  A twenty ton boiler, sheared from all its pipe and connections was blown over twenty feet into a block wall.  Fortunately the boiler room was in a remote building and unattended at the time.  No one was injured.  Although it took B&HES less than 24 hours to install a temporary boiler an expensive loss had occurred.  The boiler operator had rewired the auxiliary low water cutoff for automatic reset because the frequent shutdowns had troubled him.  The primary low water cutoff continued to control the water level in the boiler under normal water level changes.  However a slow drain down of the boiler did not allow the mechanical control to function properly.  With monthly safety checks we would have detected the problem before this disaster happened.  This accident was typical. All the boiler explosions we at B&HES have seen are traced back to boiler operator error.  (5) Training of your boiler operations personnel is another benefit of our monthly mechanical service.  As our technician performs tests and makes adjustments the boiler operator receives explanations of each step that is being taken.  Informal training like this may have prevented the accident referred to earlier.  Certainly all operators are well-intended people and would never intentionally do anything to jeopardize their companies or themselves. (6) Third Party Audit of the company's boiler maintenance program is another benefit of the monthly boiler mechanical/safety check.  Would anybody operate a business without an audit of their accounting records?  The boiler room deserves the same care. (7) Insurance Premium Reduction is yet another benefit from a monthly boiler mechanical/service contract.  Insurance companies realize that in the event of a

negligence claim, documented third party evidence shows that due care has been taken.  This evidence can lead to little or no liability settlements. It takes about four hours to perform this combustion and safety service. Any less is not enough to assure proper efficiency and safety in your boiler room. Job scope for the boiler audit should include the following items:

MONTHLY SERVICE:1. Test combustion for five points on the base fuel on which the boiler is operating. Backup fuel may be the base fuel for at least two of the twelve monthly tests. Necessary adjustments to improve fuel air ratios should be made, with readings to record efficiency and other data both before and after the adjustments are made.2. Test flame failure control.3. Test low water control cutoff and auxiliary using the slow drain method.4. Test high pressure cutoff to be done by customer's operator.5. Test gas pressure switches at high pressure cutoff and at low pressure cutoff.6. Test combustion air proving switch.7. Test auxiliary contacts on motor starter.8. Test atomizing medium proving switch.9. Test high and low fire proving switches.10. Test high and low oil temperature.11. Test low oil pressure switch.12. Remove pilot assembly, clean and adjust.13. Complete service report with recommendations.

ANNUAL SERVICE:1. Open and washout boiler water-side.2. Brush tubes and/or clean fireside surfaces.3. Replace all gaskets on water-side and fireside.4. Repack feed water pumps.5. Clean strainers.6. Replace gauge glass of DA or makeup tank.7. Test float switches on make-up tank.8. Shop rebuilt and testing of safety relief valves.

Chapter 6C

Solid-State Controls Revolutionize Boiler Maintenance

When the staff of Washington Hospital in Washington, Pennsylvania refer to "life support," included along with the respirators and heart monitors is the boiler system. Control of ambient humidity and temperature are a vital part of a hospital's maintenance system.

Washington Hospital is in the fore front of building system controls. Last year, a single compact system was installed to integrate the air handling and monitoring, water, fire protection, electrical, and pneumatic controls. Sophisticated controllers like this one are being seen in a growing number of installations, and promise to transform the controls industry.

The 1990s have taken the historically stable industry of mechanical switches and gauges into the age of solid-state. In fact, controls that until only recently were known as the most advanced technology, are being passed by. For boiler maintenance personnel trained to monitor controls by noting when circuits make or break and troubleshooting visually, mastering new electronic systems poses challenges and many opportunities.

Electronic controls offer several distinct advantages over mechanical switches.  Foremost is the safety benefit. Solid-state controls, unlike mechanical controls, cannot be bypassed. If pressure or other conditions exceed preset ranges, the control system will simply not allow operation.

A second advantage of the new controllers is constant monitoring of boiler conditions through flame safe guard (FSG) controls, also known as the programmer or primary. FSG controls keep the building engineer informed as to precisely where the burner is in its cycle. They assist the operator in preventing problems and troubleshooting those problems that arise, with an indication of what specific part of the system failed. This is a great improvement over older systems that indicated only a number, which corresponded to an entire area of the system.

In addition, these systems provide a thorough boiler and burner history through data trending. This record of such activities as the purge cycle, trial for ignition time, the number of hours in service, and number of burner cycles, greatly assists in the boiler's long-term maintenance. Furthermore, such monitoring immediately aids in fuel and energy conservation and efficiency.

Finally, electronic controls allow more features, and increasingly allow integration of all building maintenance systems. As in the Washington Hospital, a central control system can be relied upon to monitor numerous maintenance activities, which allows the operator to be more effective in his or her many responsibilities.

For building maintenance personnel, such systems allow ease of use through touch-screen control on a personal computer; single-point access to all of the building's controls and monitors; video tutorials; and optional remote video cameras for monitoring of equipment in distant locations. Even operators unfamiliar with computers find the newest control systems easy to use, because "virtual control panels" displayed on the computer screen look and feel like actual physical control panels.

The transformation in the controls industry began in 1991. A microprocessor-based integrated control system when used with gas, oil, or combination burners, provided enhanced safety when compared to mechanical switches and allowed constant monitoring of boiler conditions. It replaced the following components on a typical steam boiler: the existing programmer, steam and modulating pressure controls, gas and oil pressure switches, oil temperature switches, and the standard modulating motor.

Some controls have a communication interface and software, which will allow multiple systems to communicate with a personal computer. Using real time burner status, the system is able to send boiler shutdown notification to any desired site through a local personal computer or to one miles away through a modem. In the event of a shutdown, the system can be programmed to automatically dial a telephone number and display a message on the receiving personal computer.

This is an exciting time for those involved in boiler maintenance and control. Today's operators have the unique opportunity to gain expertise with the new controls as they become more advanced and complex. At the same time, personnel are capable of more effective boiler operation with greater efficiency and safety.

Boiler controls technology will not likely come to a halt, either. The more complex, but user-friendly technology continues to advance at a rapid pace. As future development becomes available, progress will be seen in the following applications:Systems Integration As control manufacturers provide devices which have the ability to communicate, the separate systems will be able to network into one large integral package. This capability will allow the facility manager to comprehensively monitor and control their facility.Systems Diagnostics Control capability has assisted the service of burner/boiler controls in many ways. Current technology will help build future controls and further reduce the complexity and wasted time associated with an inoperable system. Advancements in controls will allow for troubleshooting and help correct problems quickly.Enhanced Safety With current and developing technology controls, additional safety checks can be added to enhance overall plant and equipment safety.

Even though this advanced boiler/burner control technology provides many operational, safety and maintenance benefits, it cannot eliminate the human factor. Equipment operators are still needed in order for these systems to function properly.  Furthermore, equipment inspections are still a vital part of the inspectors' role. Knowledge of this new technology through training is in order for all maintenance technicians, supervisors and inspectors. The education they receive will ultimately affect the maintenance of these new controls and the process by which the controls are tested.

Chapter 7

BOILER OPERATIONA boiler operates using the feedwater system, the steam system, the fuel system and the draft system.  The feedwater system supplies water to the boiler.  The steam system controls and directs the steam produced in the boiler.   The fuel system supplies fuel and controls combustion to produce heat.  The draft system regulates the movement of air for combustion and evacuates gases of combustion. Water, steam fittings and accessories are required to supply and control water and steam in the boiler.  Boiler fittings or trim are components such as valves directly attached to the boiler. Accessories are pieces of equipment not necessarily attached to the boiler, but required for the operation of the boiler.   Safety Valves are the most important fittings on the boiler.  They should open to release pressure when pressure inside the boiler exceeds the maximum allowable working pressure or MAWP.  Safety valves are installed at the highest part of the steam side of the boiler.  No other valve shall be installed between the boiler and the safety valve.  Safety valve capacity is measured in the amount of the steam that can be discharged per hour.  The safety valve will remain open until sufficient steam is released and there is a specific amount of drop in pressure.  This drop in pressure is the blowdown of the safety valve.  Safety valve capacity and blowdown is listed on the data plate on the safety valve.  Spring loaded safety valves are the most common safety valves.  A spring exerts pressure on the valve against the valve seat to keep the valve closed.  When pressure inside the boiler exceeds the set popping pressure, the pressure forces the valve open to release.   The ASME Code specifies the design, materials and construction of safety valves.   The number of safety valves required and the frequency and procedures for testing safety valves is also specified by the ASME Code.  Adjustment or repairs to safety valves must be performed by the manufacturer or an assembler authorized by the manufacturer.Water fittings and accessories control the amount, pressure and temperature of water supplied to and from the boiler.  Water in the boiler must be maintained at the normal operating water level or NOWL.  Low water conditions can damage the boiler and could cause a boiler explosion. High water conditions can cause carryover.  Carryover occurs when small water droplets are carried in steam lines.  Carryover can result in water hammer.  Water hammer is a banging condition caused by hydraulic pressure that can damage equipment. Feedwater Valves control the flow of feedwater from the feedwater pump to the boiler.   Feedwater stop valves are globe valves located on the feedwater line.  They isolate the boiler from feedwater accessories. The feedwater stop valve is positioned closest to the boiler to stop the flow of water out of the boiler for maintenance, or if the check valve malfunctions.  The feedwater check valve is located next to the feedwater stop valve and prevents feedwater from flowing from the boiler back to the feedwater pump.  The feedwater check valve opens

and closes automatically with a swinging disc.  When water is fed to the boiler it opens.  If water flows back from the boiler the valve closes. Water Column minimizes the water turbulence in the gage glass to provide accurate water level reading.   Water columns are located at the NOWL, with the lowest part of the water column positioned at least 3" above the heating system.  Water columns for high pressure boilers consist of the main column and three tricocks.  High and low water alarms or whistles may be attached to the top and bottom tricocks.The Gage Glass is used to visually monitor the water level in the boiler.  Isolation valves located at the top and bottom permit the changing of gage glasses. A Blowdown Valve at the bottom of the gage glass is used to remove sludge and sediment.   Tubular gage glasses are used for pressure up to 400 psig. All boilers must have two methods of determining the boiler water level.  The gage glass serves as the primary method of determining boiler water level.  If the water cannot be seen in the gage glass, the tricocks are used as a secondary method of determining boiler water level.   The middle tricock is located at the NOWL.  If water comes out of the middle tricock, the gage glass is not functioning properly.  If water comes out of the top tricock, there is a high water condition in the boiler.  If water comes out of the bottom tricock, water may be safely added to the boiler. If steam comes out of the bottom tricock, water must not be added to the boiler.  Secure the fuel immediately.   Adding water could cause a boiler explosion. Makeup Water replaces boiler water lost from leaks or from the lack of condensate returned in the boiler.   Makeup water is fed manually or automatically.  Boilers can have both manual and automatic systems.  If the boiler has both, the manual always bypasses the automatic system. Boiler operators must know how to supply makeup water quickly to the boiler in the event of a low water condition.   Manual systems feed city water with a hand operated valve.  Automatic systems feed city water with a float control valve mounted slightly below the NOWL.  If the float drops from a low water level, the valve in the city water line is open.  As the water level rises, the float rises to close the valve. The Low Water Fuel Cut Off shuts off fuel to the burner in the event of a low water condition in the boiler.  The low water fuel cut off is located 2" to 6" below the NOWL.  Low water fuel cut offs are available with or without an integral water column.  Low water fuel cut offs must be tested monthly or more often depending on plant procedures and requirements.  Low water fuel cut offs operate using an electric probe or a float sensor.  The float senses a drop in water level.  Switches in the low water fuel cut off are wired to the burner control to shut off fuel to the burner when the water level drops in the chamber. The Feedwater Regulator maintains the NOWL in the boiler by controlling the amount of condensate return pumped to the boiler from the condensate return

tank.  The correct water level is maintained with a feedwater regulator, but boiler water level must still be checked periodically by the boiler operator. Feedwater Pumps are used with feedwater regulators to pump feedwater to the boiler.  Pressure must be sufficient to overcome boiler water pressure to maintain the NOWL in the boiler.  For maximum safety, plants having one steam driven feedwater pump must have a back up feedwater pump driven by electricity.  Feedwater pumps may be reciprocating, centrifugal or turbine.  Reciprocating feedwater pumps are steam driven and use a piston to discharge water to the feedwater line.  They are limited in capacity and are used on small boilers.  Centrifugal feedwater pumps are electric motor or steam driven.  They are the most common feedwater pump.  Centrifugal force moves water to the outside edge of the rotating impeller.  The casing directs water from the impeller to the discharge piping.  Discharge pressure is dependent on impeller speed.   Turbine feedwater pumps are steam driven and operate similarly to centrifugal feedwater pumps.  Feedwater Heaters heat water before it enters the boiler drum to remove oxygen and other gases which may cause corrosion.  Feedwater heaters are either open or closed.  Open feedwater heaters allow steam and water to mix as they enter an enclosed steel chamber.   They are located above the feedwater pump to produce a positive pressure on the suction side of the pump.  Closed feedwater heaters have a large number of tubes inside an enclosed steel vessel.  Steam and water do not come in contact, but feedwater goes through the tubes and steam is allowed in the vessel to preheat the feedwater.  They are located on the discharge side of the feedwater pump. Bottom Blowdown Valves release water from the boiler to reduce water level, remove sludge and sediment, reduce chemical concentrations or drain the boiler.  Two valves are commonly used, a quick opening and screw valve.  During blowdown the quick opening valve is opened first, the screw valve is opened next and takes the wear and tear from blowdown.  Water is discharged to the blowdown tank.  A blowdown tank collects water to protect the sewer from the hot boiler water.  After blowdown, the screw valve is closed first and the quick opening valve is closed last. Steam Fittings & Accessories remove air, control steam flow, and maintain the required steam pressure in the boiler.  Steam fittings are also used to direct steam to various locations for heating and process. Steam Pressure Gages and vacuum gages monitor pressure inside the boiler.  The range of these gages should be 1-1/2 to 2 times the MAWP of the boiler.  For example: on a low pressure boiler, a maximum steam pressure on the pressure gage reads 30 psig as the MAWP is 15 psig.Steam Valves commonly used include a gate valve used for the main steam stop valve and the globe valve.   The main steam stop valve cuts the boiler in

online allowing steam to flow from the boiler or takes it off line.  This is an outside stem and yoke or OS&Y valve.   The position of the stem indicates whether the valve is open or closed.  The valve is opened with the stem out and closed with the stem in.  This provides quick information to the boiler operator.The globe valve controls the flow of steam passing under the valve seat through the valve.  This change in direction causes a decrease in steam pressure.  A globe valve decreases steam flow and can be used to vary the amount of steam flow.  This should never be used as a main steam stop valve. Steam Traps remove condensate from steam in lines from the boiler.  Steam traps work automatically and increase boiler plant efficiency.  They also prevent water hammer by expelling air and condensate from the steam lines without loss of steam.  Steam traps are located after the main steam header throughout the system.  Steam traps commonly used include the inverted bucket, the thermostatic and the float thermostatic.  In the inverted bucket steam trap steam enters the bottom flowing into the inverted bucket.  The steam holds the bucket up.   As condensate fills the steam trap the bucket loses buoyancy and sinks to open the discharge valve.  The thermostatic steam trap has a bellows filled with a fluid that boils at steam temperature.  As the fluid boils vapors expand the bellows to push the valve closed.  When the temperature drops below steam temperature, the bellows contract to open the valve and discharge condensate. A variation of the thermostatic steam trap is the float thermostatic steam trap.  A float opens and closes depending on the amount of condensate in the trap bowl.  Condensate is drawn out by return vacuum. Steam Strainers remove scale or dirt from the steam and are located in the piping prior to steam trap inlet.   Scale or dirt can clog discharge orifices in the steam trap.  Steam strainers must be cleaned regularly. SUMMARYThe safety valve is the most important fitting on the boiler.  The gage glass is used to visually monitor the water level in the boiler.   Tricocks are used as a secondary device for determining water level in the boiler.   Makeup water replaces water lost from leaks or lack of condensate return to the boiler.  The low water fuel cut off shuts off fuel to the burner in the event of a low water condition.  Steam pressure gages and vacuum gages are used to indicate the pressure inside the boiler.

Chapter 8B

ELECTRONIC VALVE TESTING The safety relief valve, sometimes referred to as the "silent sentential," has an extremely important role in the operation of the boiler or pressure vessel.  The perfecting of the safety relief valve (SRV) made a big difference in bringing the boiler industry from the "dark ages" of dangerous explosions to a predictably safe operation. SRV’s are manufactured under the control of American Society of Mechanical Engineers (ASME).  Approved assemblers and repair facilities, such as The Valve Shop, are authorized and approved by the ASME to make adjustments and stamp boiler safety valves with the "V" symbol and for safety valves on unfired vessels the "UV" symbol.  Repairs of SRV’s are performed by The Valve Shop under the control of the National Board of Boiler & Pressure Vessel Inspections (National Board) and bears the "VR" symbol. The major short coming of the SRV’s is the lack of an effective method to determine the valve’s operating status.  Increasing the pressure of the boiler until the valve relieves would be one method but could possibly lead to over pressuring of the boiler controls or the plant process equipment.  Raising the lifting lever is another method to see if the valve is relieving properly but that approach does not allow for any information on the point of relief.  Neither of these methods is very effective because anytime the valve relieves it is very likely that particles in the steam will collect or the steam will cut the disc or seat allowing the steam to leak through the valve.  The only valid alternative has been to periodically send the valves to a qualified "VR" valve shop for rebuilding, testing and resetting the pressure.  The results are sure but the shortcomings are (1) how often is this needed and (2) it is very expensive. 

Now there is a new alternative brought about by the use of computers.  The automated valve electronic test unit combines the computer with a hydraulic lifting device.  The valve stem will be lifted by the hydraulic lifting device until the computer with its predetermined data on the valve will stop the lift just short of the point of blowing and in doing so determine the set pressure of the valve.  The advantages of this approach are enormous.  First, the SRV is tested with the electronic valve tester when at operating pressure which means that the boiler does not have to be taken off line unless the SRV fails

the test.  Second, the cost of testing six to eight valves in the field is about the same as the cost of rebuilding one valve in the shop.  Third, since the electronic valve tester does not lift the valve from its seat reseating problems are not an issue. The electronic valve tester is amazingly accurate and is now recognized by most insurers as an acceptable alternative to sending the valve to the "VR" shop for testing.  The National Board recognizes it as part of the quality control manual of the valve repair shop.  The customer is provided with a printout including a graph of each valve tested.  This can provide a valuable record for documentation in the customer boiler quality/safety compliance program and to establish guidelines for future repair scheduling for the repair of SRV’s. "Why don’t all repair shops own this type equipment?"  Quite possibly because of the high purchase cost, which exceeds $50,000, and also it reduces the number of valves available for repair.  But the effectiveness of this service means that the valve repair companies must offer it and will maintain their repair volume by increasing their customer base.

Chapter 9B

BOILER STORAGE PROCEDURESMany facilities have excess boiler capacity in the form of standby units.  Choosing the best way to properly protect the equipment from oxygen pitting and/or general corrosion can be quite a challenge.  The most commonly known and utilized methods are (1) wet storage and (2) dry storage.  There is also a third less known method available (3) hot/wet storage.  Before discussing the different alternatives, the status of the standby equipment must be classified by the need for future operation:

Equipment which will not be required to operate at a moments notice.   An example of this may be a facility that has an extra "Standby" unit not required for its operation and a facility that may be closed and it's boiler(s) idled for an indefinite period of time.

Equipment that may be needed at a moments notice. For instance, the operating unit has a flame failure and after several unsuccessful attempts to restart the boiler it becomes clear you have a major problem. As the system steam pressure continues to drop the need for  "Emergency Standby" occurs.

Now that we have classified the equipment it is time to discuss the different options available:

DRY STORAGE: This method is preferred whenever a boiler is in standby allowing time to prepare the unit for operation. Be sure the unit is completely drained and dry. If possible, heaters should be used to maintain the temperature of all surfaces above the dew point. Then a desiccant should be applied to either watertight wood or corrosion resistant trays as follows:

1. Quick Lime-at six pounds per 100 cubic ft. volume OR2. Silica Gel–at eight pounds per 100 cubic feet of volume

With another boiler operating in the boiler room, to assure low humidity in the air, the trays should be placed in each drum of a watertube boiler or on the top tubes of a firetube boiler. The feedwater inlet and steam outlet should be checked to ensure no dampness occurs in the boiler from these points. All manhole and hand-hole covers should remain opened to allow dry air to enter the unit. Be sure to inspect the boiler internals every month to ensure against any moisture. When the desiccant becomes hard due to absorbing moisture, be sure to promptly replace it.

WET STORAGE: This method is most commonly used whenever a boiler is in "Standby", allowing time to prepare the unit for operation. The boiler should be filled to its normal level using deaerated feedwater whenever possible. Add three pounds of caustic soda and one and one half pounds of sodium sulfite per 1000 gallons of water capacity. Then open boiler vents, apply heat for one to two hours, and allow the unit to cool for an hour after firing. Then completely fill the unit with deaerated feedwater. All boiler vents and drains should now be closed and the drain between the non-return and the main steam stop valve should be left fully opened. The boiler water should be tested periodically and additional chemical added as needed to maintain sulfite at a minimum of 100 ppm and p-alkalinity at a minimum of 400 ppm.

HOT WET STORAGE: This method uses hot treated blowdown from an operating boiler to keep an "Emergency Standby" unit protected and ready to operate at a moments notice. It is accomplished by connecting the continuous blowdown line from the operating unit to a bottom blowdown location of the standby unit. With all vents closed on the standby unit and the continuous blowdown line opened, the hot treated water from the operating boiler continuous blowdown will pass into the bottom of the standby unit and out the continuous blowdown line to the blowdown flash tank. 

Chapter 10

REFERENCESLinks:   National Board of Boiler & Pressure Vessel InspectorsNatural Gas Prices at the Well Head www.amazon.comHigh Pressure Boilers                 by Frederick M. Steingress, Harold J. Frost Steam Plant Operation         by Thomas F. Lammers, Everett B. Woodruff Boiler Operator's Guide         by Anthony Lawrence Kohan Water Treatment Essentials for Boiler Plant Operation                 by Robert G. Nunn

Boiler Room Units of Measure1 Boiler Horsepower = 34.5 pounds steam from and at 212°F

1 Boiler Horsepower = 33,480 Btu1 gallon water = 8.34 pounds1 cu ft water = 7.48 gallons1 cu ft resin = 30,000 grains1 grain hardness = 17.1 ppm

Psig (gauge) + 14.7 = Psia (absolute)°C = (°F - 32) x 5/9°F = (9/5 x °C) + 32

Btu steam output = Btu input x efficiency1 psi = 27.7 inches water column

1 psi = 16 oz 

Fuel Values-Standard#6 oil = 150,000 Btu/gallon#4 oil = 145,000 Btu/gallon#2 oil = 140,000 Btu/gallon

Natural Gas = 1,000 Btu/cubic foot1 Therm = 100,000 Btu 

Propane = 91,500 Btu/gallonCoal = 12,000 Btu/pound

Wood - Dry = 8,000 Btu/poundWood - Wet = 4,500 Btu/pound

1kw electricity = 3413 Btu

TABLE FOR STEAM/WATER--HEAT VALUES

TEMPERATURE

PRESSUREVAPOR SATURATED

STEAM-BTU'S/LBTEM

P

DegF DegC PSIG VOLUME

LIQUID

LATENT

TOTAL

DegF

32.0 0.0 -14.6 3305.0 -0.02 1075.5 1075.5 32.0

40.0 4.4 -14.6 2446.0 8.03 1071.0 1079.0 40.0

50.0 10.0 -14.5 1704.8 18.05 1065.3 1083.4 50.0

60.0 15.5 -14.4 1207.6 28.06 1059.7 1087.8 60.0

70.0 21.1 -14.3 868.4 38.05 1054.0 1092.1 70.0

80.0 26.7 -14.2 633.3 48.04 1048.4 1096.4 80.0

90.0 32.2 -14.0 468.1 58.02 1042.7 1100.7 90.0

100.0 37.8 -13.7 350.4 68.00 1037.1 1105.1

100.0

110.0 43.3 -13.4 265.4 77.98 1031.4 1109.4

110.0

120.0 48.9 -13.0 203.26 87.97 1025.6 1113.6

120.0

130.0 54.4 -12.5 157.33 97.96 1019.8 1117.8

130.0

140.0 60.0 -11.8 123.00 107.95 1014.0 1122.

0 140.

0

150.0 65.5 -11.0 97.07 117.95 1008.2 1126.

2 150.

0

160.0 71.1 -10.0 77.29 127.96 1002.2 1130.

2 160.

0

170.0 76.7 -8.7 62.06 137.97 996.2 1134.

2 170.

0

180.0 82.2 -7.2 50.22 148.00 990.2 1138.

2 180.

0

190.0 87.8 -5.4 40.96 158.04 984.1 1142.

1 190.

0

200.0 93.3 -3.2 33.64 168.09 977.9 1146.

0 200.

0

210.0 98.9 -0.6 27.82 178.15 971.6 1149.

8 210.

0

212.0 100.0 0.0 26.80 180.17 970.3 1150.

5 212.

0

220.0 104.4 2.5 23.15 188.22 965.2 1153.

4 220.

0

230.0 110.0 6.1 19.381 198.33 958.7 1157.

0 230.

0

240.0 115.5 10.3 16.321 208.45 952.1 1160.

6 240.

0

250.0 121.1 15.0 13.819 218.59 945.4 1164.

0 250.

0

260.0 126.7 20.7 11.762 228.76 938.6 1167.

4 260.

0

270.0 132.2 27.2 10.060 238.95 931.7 1170.

7 270.

0

280.0 137.8 34.5 8.644 249.17 924.6 1173.

8 280.

0

290.0 143.3 42.9 7.460 259.4 917.4 1176.8

290.0

300.0 148.9 52.3 6.466 269.7 910.0 1179.7

300.0

310.0 154.4 63.0 5.626 280.0 902.5 1182.5

310.0

320.0 160.0 74.9 4.914 290.4 894.8 1185.2

320.0

340.0 171.1 103.3 3.788 311.3 878.8 1190.1

340.0

360.0 182.2 138.3 2.957 332.3 862.1 1194.4

360.0

400.0 204.4 232.6 1.8630 375.1 825.9 1201.0

400.0

420.0 215.5 294.1 1.4997 396.9 806.2 1203.1

420.0

440.0 226.7 366.8 1.2169 419.0 785.4 1204.4

440.0

460.0 237.8 452.2 0.9942 441.5 763.2 1204.7

460.0

480.0 248.9 551.5 0.8172 464.5 739.6 1204.1

480.0

500.0 260.0 666.2 0.6749 487.9 714.3 1202.2

500.0

520.0 271.1 797.8 0.5596 512.0 687.0 1199.0

520.0

540.0 282.2 948.1 0.4651 536.8 657.5 1194.3

540.0

580.0 304.4 1311.5 0.3222 589.1 589.9 1179.0

580.0

600.0 315.5 1528.5 0.2675 617.1 550.6 1167.7

600.0

640.0 337.8 2045.2 0.1802 679.1 454.6 1133.7

640.0

700.0 371.1 3079.6 0.0752 822.4 172.7 995.1 700.0

705.5 374.2 3193.5 0.0508 906.0 0.0 906.0 705.5