INTRODUCTION TO BOILERS Chapter 1 A boiler is an enclosed vessel that provides a means for 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, and the gas is 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 o F it is assumed that its heat value is zero. On-line:1
The heat required to change the temperature of a substance is called its sensible heat. In the teapot illustration to the left the 70 o F water contains 38 Btu s and by adding 142 Btu s the water is brought to boiling point. In the illustration to the right, 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. Sensible 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 o F. This occurs in the boiler. In the example to the right, the boiler is operating at a pressure of 100 psig which gives a steam temperature of 338 o F or 1185 Btu s. Latent Heat 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 Superior Firetube Boilers 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, On-line:2
HRT or horizontal return tube. Firetube boilers typically have a lower initial cost, are more fuel efficient and easier to operate but they are limited generally to capacities of 50,000pph and pressures of 300 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 Vertical tubeless boilers are used for small loads but really do not fit into either category as they do not have tubes. On-line:3
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 160 o F 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 180 o F 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 have universally adopted the National Board of Boiler & Pressure Vessel Inspectors (National Board Inspector Code) and some require the vessel to be affixed with the national board R stamp. STEAM BOILER SYSTEMS: The feedwater system provides water to the boiler. A level control on the boiler 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 strainer traveling then to the fuel oil pump. The fuel oil is 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 On-line:4
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. Most 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: 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 or process. As the steam releases heat it cools and 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. On-line:5
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, boiler chemicals are added to react with the solids creating 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 On-line:6
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. On-line:7
MAKEUP WATER Chapter 2 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 remains. 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 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. On-line:8
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 has allowed users to depend on smaller units with more frequent regeneration. Simplex Softener Duplex Softener Triplex Softener On-line:9
REGENERATION PROCESS BACKWASH: 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 and 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 /R C = Capacity of softener in cubic feet of resin M = 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 cycles H = Hardness of water in grains (17.1 ppm per grain hardness) R = Resin Capacity per cubic foot (this is virtually always 30,000 grains) On-line:10
BOILER FEEDWATER Chapter 3 A. DEAERATION: All natural waters contain dissolved gases in solution. Certain gases, such as carbon dioxide and oxygen, greatly increase corrosives. 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. On-line:11
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. On-line:12
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 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 known 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. On-line:13
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 On-line:14
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. 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. Boiler Operation Costs On-line:15
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 effects 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 affect 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. On-line:16
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. On-line:17
Injection Quill Feed chelant products continuously to boiler feedwater line, preferably after the economizer. Use a 304 SS injection quill. 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). Feed chelant only downstream from copper or copper alloys. Feed catalyzed sulfite or a suitable oxygen scavenger to the storage section of the deaerating heater. Assure that the feedwater mixes with boiler water before entering downcomer tubes. 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. On-line:18
CONDENSATE RETURN SYSTEM Chapter 5 When 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 pre-treating (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. On-line:19
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 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 of car wax on an automobile. 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. 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. On-line:20
COMBUSTION & CONTROLS On-line:21 Chapter 6 Combustion 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 pre-purging the furnace. By pre-purging 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 On-line:22
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. On-line:23 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 WARE less than 24 hours to install a temporary 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 WARE 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 On-line:24