Boiler Feedwater Pump Balancing Line

Boiler Feedwater Pump Balancing Line

Due to pressure difference across the pump there is always thrust on the rotor toward suction side of pump due to fluid. Therefore, there balancing system is required.

Balancing drum

Balancing drum is cylindrical portion installed on the rotor of the pump generally at the discharge end side. Small gap in mm is maintained axially between casing or dummy piston which is stationary part attached with pump casing.

One side of balancing drum, pressure=discharge pressure while another side of balancing drum, the pressure =suction pressure (slightly greater than suction pr. which is maintained by a balancing line connected to suction line of pump. Therefore, due to pressure difference across balancing drum there is thrust which will opposite to the thrust created by fluid.

Balancing Disks

The operation of the simple balancing disk is illustrated in Figure above. The disk is fixed to and rotates with the shaft. It is separated by a small axial clearance from the balancing disk head, or balancing sleeve, which is fixed to the casing. The leakage through this clearance flows into the balancing chamber and from there either to the pump suction or to the vessel from which the pump takes its suction. The back of the balancing disk is subject to the balancing chamber back pressure, whereas the disk face experiences a range of pressures. These vary from discharge pressure at its smallest diameter to back pressure at its periphery. The inner and outer disk diameters are chosen so that the difference between the total force acting on the disk face and that acting on its back will balance the impeller axial thrust.

If the axial thrust of the impellers should exceed the thrust acting on the disk during operation, the latter is moved toward the disk head, reducing the axial clearance between the disk and the disk head. The amount of leakage through the clearance is reduced so that the friction losses in the leakage return line are also reduced, lowering the back pressure in the balancing chamber. This lowering of pressure automatically increases the pressure difference acting on the disk and moves it away from the disk head, increasing the clearance. Now the pressure builds up in the balancing chamber, and the disk is again moved toward the disk head until an equilibrium is reached.

To assure proper balancing in disk operation, the change in back pressure in the balancing chamber must be of an appreciable magnitude. Thus, with the balancing disk wide open with respect to the disk head, the back pressure must be substantially higher than the suction pressure to give a resultant force that restores the normal disk position. This can be accomplished by introducing a restricting orifice in the leakage return line that increases back pressure when leakage past the disk increases beyond normal. The disadvantage of this arrangement is that the pressure on the seal chamber is variable, a condition that may be injurious to the life of the seal and therefore should avoided.

PRINCIPLE OF CIRCULATION

1. Principles of Circulation

Subcooled FW enters the drum, mixes with the circulating boiler water, and attains saturation temperature instantly, as the boiling, circulating water is several times the incoming water flow.

This circulating water picks up its latent heat progressively from the hot flue gases to form steam as it goes around the evaporator circuits several times. This steam is continuously separated in the drum by the steam separators. There is a balance between the incoming feed water (FW) and the outgoing steam when the system is properly functioning.

Circulation ratio is the water in circulation divided by the steam fl ow. In other words it is the number of times the water has to go around the various evaporator circuits before it is all converted into steam. Latent heat is added to the circulating water at constant pressure and constant temperature.

There is no circulation in SC boilers as it is a forced fl ow arrangement. In once-through (OT) subcritical boilers also there is no circulation. To take advantage of the relatively low boiling temperature of water (critical temperature is 374.1°C), the hottest portion of the boiler, namely, the furnace, is encased in tubes carrying boiling, circulating water. The screen, division wall, boiler bank (BB), and EVAP tubes also form parts of the circulating system.

It therefore follows that the most important use of circulating water is extracting high amounts of heat, particularly in the furnace, to keep the tubes cool. This is only possible as long as the steam bubble formation on the inside of tubes does not give way to a film of steam. In other words the departure from nucleate boiling (DNB) does not set in.

It is important to remember that a boiler is not designed for circulation, but for cooling the gases with ECON, evaporator, SH, and RH surfaces. It is then checked for circulation.

Adequacy of circulation to prevent DNB is vital in all conditions of operation—at all loads with all fuels and combinations. It means that the velocities of steam–water mixture at all points are high enough to keep the tubes wet with no DNB. This is the essence of circulation requirement, and circulation check should be performed to verify that this condition is fully met. Usually, changes to the supply and riser tube geometry that feed and collect the water–steam mixtures, respectively, in the various circuits are needed to remedy the defi ciencies. At times, other measures such as fitting of ferrules, using ribbed/rifled tubes, and so on may also be needed.

2. Flow in Vertical and Horizontal Tubes



2. Flow in Vertical and Horizontal Tubes



1. Tube A is bubble fl ow with low velocity and a few steam bubbles in a predominant
water flow.
2. Tube B is emulsion fl ow where the steam bubbles increase and hence produce froth.
3. Tube C is slug fl ow with fi ne bubbles coalescing to form big bubbles almost fi lling the bore of the tube.
4. Tube D is wet wall fl ow where the steam fi lls the tube with an annular fi lm of water cooling the tube.
5. Tube E is dry wall fl ow where the water fi lm is replaced by a thin steam film that has poor cooling ability.

In a horizontal tube the fl ow patterns are different. Owing to the density difference, all the steam bubbles migrate to the top of the tube and slide along the tube wall.

1. At higher velocities (Tube A) of >1 m/s, the steam bubbles join together and move
along with water, resembling wet water fl ow.
2. At low velocities (Tube B) of <0.5>250,000 kcal/m2 h or 92,000 Btu/ft2 h) cannot be avoided, particularly in the burner zone. There is a limit to increasing the velocities at (higher) pressures >150 bar when the circulation ratios are on the lower side.

Ribbed or rifl ed tubes are helpful in delaying the onset of DNB when compared to smooth tubes, as they offer more wetted surface for adherence of water film. The permissible steam by weight percentage (%SBW) for the same heat flux is raised from a range of 20–40% level to a range of 70–90% level by the use of ribbed tubes. Since they are expensive, they are employed around the burner zone and mainly in high pressure and SC boilers.

To maintain wet wall flow or nucleate boiling under all conditions, the following criteria must be satisfi ed for each circuit. A circuit is a set of heated tubes of similar shape and heat input that allow upward fl ow of water.

1. Exit quality. SBW at the top of any circuit should be less than a specifi ed limit depending on the drum pressure and the location of burners—whether at the top or bottom—to prevent film boiling at the top of the circuit.

2. Minimum velocity. Water velocity at the commencement of the circuit should exceed
a specifi ed limit, depending on the inclination of the tubes to prevent the steam bubbles from adhering to the tube walls, causing overheating, and also to prevent sludge accumulation.

3. Saturated water head (SWH). The SWH, the ratio of pressure loss (including static head) to the pressure produced by a column of saturated water of the same height, is required to be at a certain specifi ed minimum to prevent fl ow reversal. The usual remedy for meeting this requirement is to increase the water fl ow to the defaulting circuit.

DESIGN OF HEATING SURFACES

DESIGN OF HEATING SURFACES

The first step in the design of heating surfaces is determining the heat duties of different components of the boiler heating surfaces. Atypical boiler would use the following four types of heating surfaces:

Economizer
Evaporator
Superheater
Reheater (for reheat boilers)

Heat duty of these elements depends on the designed steam parameter of the boiler. It is best illustrated by an example (Figure 1), which shows how the relative heat duty of different boiler elements changes with steam pressure. As the steam pressure increases, the heat duty of the evaporator decreases and that of superheater increases.



Figure 1

At low pressure the evaporator duty is so high that a water wall or wing wall alone cannot absorb the required amount of heat. So, a separate heating surface, called bank tubes, is needed. After the heat duties of individual elements (economizer, evaporator, superheater, and reheater) are determined by the steam table, their disposition can be determined. From the viewpoint of heat absorption, a CFB boiler may be divided into two regions, the CFB loop and back-pass


1.1. Primary Loop
The CFB loop includes the furnace, cyclone/impact separator, loop-seal, and external heat exchanger.

2.2. Secondary Loop or Back-pass
The back-pass is the section of gas pass between the exit of the cyclone/impact separator and the exit of the air heater. The furnace usually accommodates:
 Evaporator tubes
 Parts of the superheater
 Parts of or the entire reheater

The economizer is normally located in the back-pass between the superheater and the air heater. Evaporator tubes may form the walls of the furnace and those of the back-pass. Parts of it may also be located in the external heat exchanger. Sometimes, the superheater tubes also form parts of the back-pass enclosure. The disposition of the reheater and superheater tubes in the furnace, back-pass, and external heat exchanger is the designer’s choice. This choice is, however, influenced by the type of fuel, as shown below. Some designs also use a steam-cooled cyclone

Reference:
1. Gottung, E. J. and Darling, S. L., Design considerations for CFB steam generators, In Proceedings of the 10th International Conference on Fluidized Bed Combustion.
2. Combustion and gasification in fluidized beds By Prabir Basu.

ASH SCREW COOLER

1.1. Bottom Ash Ash is discharge from the bottom of the combustor to maintain the required inventory. Higher bed pressure drop as an indication of accumulation of over size particle-mostly stones, shale, and agglomerated ash. Usually bottom ash draining is periodically operation as the bed ash quantity is generally <10%>

1.2. Ash Screw Cooler Water-cooled ash screw cooler shown in figure.1 below, is a good solution for dry ash discharge that is environtmentally more more acceptable. Ash from the bed is drained into screw whose flights, shaft and casing are all cooled by softened water of high quality.

Figure.1 Ash Screw Cooler

1.3. Holo-Flite dryer / screw cooler
Metso's Holo-Flite® thermal processor is an indirect heat exchanger utilizing a hollow screw for heating, cooling or drying bulk solids, filter cakes, pastes or sludges. It is a proven and efficient thermal processor with over 3000 installations worldwide.(http://www.metso.com)

In the Metso Holo-Flite® processor, individual particles are heated or cooled as they come in contact with the surfaces of the hollow flights, shaft and trough. The product to be processed is continuously conveyed in an axial direction by means of the rotating screw fl ights along a jacketed trough.

Figure.2 Ash Screw Cooler - Hollow Flite

Reference:
1. Boilers for Power and Process By Kumar Rayaprolu
2. Hollow-Flite .(http://www.metso.com)

Igniter Classification

Igniter Classification.

Igniter: A permanently installed device that provides proven ignition energy to light off the main burner.

Class 1 Igniter. An igniter that is applied to ignite the fuel input through the burner and to support ignition under any burner light-off or operating conditions. Its location and capacity are such that it will provide sufficient ignition energy, generally in excess of 10 percent of full load burner input, at its associated burner to raise any credible combination of burner inputs of both fuel and air above the minimum ignition temperature.

Class 2 Igniter. An igniter that is applied to ignite the fuel input through the burner under prescribed lightoff conditions. It is also used to support ignition under low load or certain adverse operating conditions. The range of capacity of such igniters is generally 4 percent to 10 percent
of full load burner fuel input.

Class 3 Igniter. Asmall igniter applied particularly to fuel gas and fuel oil burners to ignite the fuel input to the burner under prescribed light-off conditions. The capacity of such igniters generally does not exceed 4 percent of the full load burner fuel input.

Class 3 Special Igniter. A special Class 3 high energy electrical igniter capable of directly igniting the main burner fuel.

Reference:
1. NFPA 85 Boiler and Combustion Systems Hazards Code (Edition 2007)

HRSG Duct Burner - Combustion Air

Combustion Air and Turbine Exhaust Gas

Temperature and Composition

Oxygen used for supplementary firing in HRSG co-generation applications is provided by the residual in the turbine exhaust gas instead of from an external source of air. Because this flue gas is already at an elevated temperature, duct burner thermal efficiency can approach 100%, as relatively little heat is required to raise the combustion product temperature to the final fired temperature entering the boiler. TEG, however, contains less oxygen than fresh air, typically between 11 and 16% by volume, which in conjunction with the TEG temperature significantly affects the combustion process. As the oxygen concentration and TEG temperature decrease, products of incomplete combustion (CO and unburned hydrocarbons) occur more readily, eventually progressing to combustion instability.
The effect of low oxygen concentrations can be partially offset by higher temperature; and, conversely, higher oxygen concentrations will partially offset the detrimental effects of low TEG temperatures. This general relationship is shown in this figure.

The burner can then be designed to create a local hightemperature condition for stable combustion, while not allowing premature quenching by the remaining excess TEG. Flame speed is another measure of combustibility and can be calculated for unusual fuel constituents. The oxygen remaining from the turbine combustion is usually many times greater than required for supplemental firing. The final concentration of O2 after supplemental firing is frequently still above 10%. In the extreme, a fully fired boiler is possible, with the residual O2 as low as 2%. Fully fired HRSGs can produce large amounts of steam but are rare because the economics favor the power-to-heat ratio of unfired or supplemental fired HRSG.

Summarize from:
1. The John Zink Combusyion Handbook
2. Industrial Burner Handbook
3. Coen Website

Hazardous Area Classification

Area Classification

The type of protective technique selected and the level of protection it must provide depend upon the potential hazard caused by using electrical apparatus in a location where a combustible, flammable, or ignitible substance may be present. Area classification schemes and systems of material classification have been developed to provide a succinct description of the hazard so that appropriate safeguards may be selected. All useful area classification systems specify the kind of flammable material that may be present and the probability that it will be present in ignitible concentrations.

4.1 North American methods
4.1.1 In the United States, area classification principles are stated in Article 500 of the National Electrical Code, ANSI/NFPA 70. Similar requirements in Canada are given in the Canadian Electrical Code, Part 1, Section 18, (CSA C22.1).
Various organizations have developed numerous guides and standards that have substantial acceptance by industry and governmental bodies for area classification.

Area classification descriptions used in the United States and Canada include the following:
Locations are classified

(1) by CLASS—the generic form of the flammable materials in the atmosphere (gas or vapor, dusts, or easily ignitible fibers or flyings);

(2) by DIVISION—an indication of the probability of the presence of the flammable material in ignitible concentration;

(3) by GROUP—the exact nature of the flammable material.

4.1.1.1 Classes
Class I locations are those in which flammable gases or vapors are, or may be, present in the air in quantities sufficient to produce explosive or ignitible mixtures.
Class II locations are those that are hazardous because of the presence of combustible dusts.
Class III locations are those in which easily ignitible fibers or flyings may be present but not likely to be in suspension in sufficient quantities to produce ignitible mixtures.

4.1.1.2 Divisions
Class 1, Division 1 locations are those in which:
a) hazardous concentrations exist continuously, intermittently, or periodically under normal operating conditions;

b) hazardous conditions may exist frequently because of repair or maintenance operations or because of leakage; or
c) breakage or faulty operation of process or other nonelectrical equipment or processes might release flammable concentrations or gases or vapors and might also cause simultaneous failure of electrical equipment that causes a source of ignition.

Class I, Division 2 locations are those in which:
a) hazardous volatile liquids, vapors, or gases are normally confined within closed
containers or closed systems from which they can escape only in case of accidental
rupture or breakdown of such containers or systems, or in case of abnormal operation
of equipment;
b) flammable concentrations are normally prevented by positive mechanical ventilation but might become hazardous through failure or abnormal operation of the ventilating system; or
c) areas adjacent to Division 1 locations to which hazardous concentrations of gases or
vapors might occasionally be communicated.
Class II, Division 1 locations are those in which:
a) combustible dust is, or may be, in suspension in the air continuously, intermittently, or periodically under normal operating conditions, in quantities sufficient to produce explosive or ignitible mixtures;
b) breakage or faulty operation of a process or machinery may produce combustible
concentrations of dusts and might also cause simultaneous failure of electrical equipment, which, in turn, may act as a source of ignition; or c) electrically conductive combustible dusts may be present.

Class II, Division 2 locations are those in which:
a) combustible concentrations of suspended dust are not likely, but where deposits or
accumulations of dust may interfere with the safe dissipation of heat from electrical
equipment or apparatus; or
b) combustible concentrations of suspended dust are not likely, but where deposits or
accumulations of dust on, in, or in the vicinity of electrical equipment might be ignited
by arcs, sparks, or burning material from such equipment.

Class III, Division 1 locations are those in which easily ignitible fibers or materials producing combustible flyings are handled, manufactured, or used.

Class III, Division 2 locations are those in which easily ignitible fibers may be stored or handled (except in the process of manufacture).

NOTE: Some plant areas in the manufacture, handling, and storage of explosives or
ammunition and nitrocellulose products (such as celluloid photographic films), etc., involve conditions that are not covered by NEC Classifications. This is particularly true where black powders, smokeless powder, dust from TNT, and other explosives are present. See NFPA 495, Reference Code for Explosive Materials, for guidance.

4.1.1.3 Groups
The United States and Canadian standards recognize seven groups: Groups A, B, C, D, E, F, and G. Groups A, B, C, and D apply to Class I locations; Groups E, F, and G apply to Class II Locations. These groups include the following:

Group A—Atmospheres containing acetylene.
Group B—Atmospheres such as butadiene*, ethylene oxide*, propylene oxide*, acrolein*, or hydrogen (or gases or vapors equivalent in hazard to hydrogen, such as manufactured gas).
Group C—Atmospheres such as cyclopropane, ethyl ether, ethylene, hydrogen sulfide, or gases or vapors of equivalent hazard.
Group D—Atmospheres such as acetone, alcohol, ammonia*, benzene, benzol, butane,
gasoline, hexane, lacquer solvent vapors, methane, naphtha, natural gas, propane, or gases or vapors of equivalent hazard.

In the United States:
Group E—Atmospheres containing combustible metal dusts regardless of resistivity or other combustible dusts of similarly hazardous characteristics having resistivity of less than 102 ohmcentimeter (magnesium, aluminum, bronze powder, etc.)

Group F—Atmospheres containing carbon black, charcoal, coal, or coke dusts that have more than 8 percent total volatile material (coal and coke dusts per ASTM 3175-82) or atmospheres containing these dusts sensitized by other materials so that they present an explosion hazard and having resistivity greater than 102 ohm-centimeter but equal to or less than 108 ohmcentimeter.

Group G—Atmospheres containing combustible dusts (flour, starch, pulverized sugar and cocoa, dairy powders, dried hay, etc.) having resistivity of 108 ohm-centimeter or greater.

NOTE: See NFPA 497M for a more detailed treatment of dusts. In Canada, the ranges of resistivities are not specified.