Fossil and Biomass Fueled Power Plants Steam Turbine AuxiliariesSteam turbines are one of the major drivers of power generators in todays power plants. There are several types of turbines and a number of mechanical arrangements to obtain maximum efficiency and output. The auxiliaries however are very similar, performing equally important tasks in their systems.

Steam Turbine AuxiliariesIntroduction In the previous article on power plant auxiliaries we looked at the important part played by the auxiliaries of a dual drum water tube boiler. Following on from there, here we will examine the main auxiliaries of the associated steam turbine, using the same method of locating and describing the functions of the different components within the relevant systems. Please refer to the drawing to when reading the component descriptions which are numbered in sequence as in the descriptions.

Lube-oil System1. PumpsThe lubricating oil system has three separate pumps which supply the bearings and hydraulic system with oil. Lube oil Jacking pump this is used when the turbine is being rotated by the turning gear. Emergency Lube oil Pump this cuts in if the turbine trips through loss of power. Lube oil Booster Pump this pump is used at start-up and ensures an adequate flow at slow speeds. It cuts out when the turbine reaches operation speed Main lube oil pump this pump draws the oil from a lube oil tank and supplies the turbine bearings and governor. This is normally a centrifugal pump driven by the turbine or generator shaft.

2. L.O. FiltersSome systems have duplex filters on the suction and discharge pipework of the pumps, but at a minimum a set on the discharge. These remove any debris picked up by the oil before the oil is fed to the bearings.

3. L.O. CoolersThe oil lubricates the bearings absorbing the heat from friction. This heat is dissipated by the coolers. These are usually tube coolers, water being the medium used to cool the oil.

4. L.O. CentrifugeThe centrifuge is usually positioned above the lube oil tank and runs continually whilst the turbine is operating, only coming off line for cleaning. It draws the lube oil from the lube oil tank removing any water and particles by centrifugal force before discharging the clean oil back to the tank.

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5. Turbine GovernorAs the loads on the generator vary requiring more or less steam to the turbine, the governor responds by controlling the speed of the turbine. The governor is hydraulically operated by lube oil supplied by the main pump.

The Steam Condensate System6. Steam Turbine CondenserExpanded steam from the low pressure turbine is drawn into the tube condenser by a vacuum which is maintained at 28"- 29"Hg where it is condensed by water which has been cooled in the cooling tower.

7. Air EjectorThe air ejectors are used to create the initial vacuum in the condenser and maintain a vacuum of 28-29"Hg for optimum steam evaporation. The ejectors draw the air out of the condenser by passing high pressure steam through a vortex piping arrangement thus causing the vacuum.

8. Condensate PumpThis pump draws the water from the bottom of the condenser or hotwell and pumps it up to the deaerator.

9. Tray DeaeratorThis is a pressure vessel with a horizontal and vertical section somewhat like a comic strip submarine shape. It effectively removes the air and oxygen from the feed water (condensate) which would otherwise damage the inside of the boiler tubes by corrosion. There are several types of deaerators; we will look at the tray type which is a vessel having a horizontal section with a vertical dome. The bottom horizontal section is used to collect and store the deaerated water; the vertical section has perforated trays set at intervals along its upper length. The condensate enters at the top of the vertical section cascading down through the trays, meeting steam injected from the sides and gathers at the bottom section where it is heated by steam coils or sprays. The air is vented from the very top of the deaerater vertical domed section.

10. Boiler Feed PumpThis pump takes the water from the deaerator and pumps it through a series of feed heaters into the boiler economizer (see boiler auxiliaries article) and into the boiler top drum through the feed water control valve. The water used to condense the steam to condensate is now pretty hot itself, so it needs to be cooled down before being used again. The cooling tower is used for this purpose. It is a vertical hyperboloid concrete structure with a honeycombed interior usually of plastic and the water enters at the top cascading down through the plastic sections. It draws in air from the bottom, which rising up through the tower mixes with the water thus cooling it helped by evaporation, the resultant plume rising out of the top of the tower.

12 Cooling Medium PumpsThese pumps circulate the cooling medium from the main vacuum condenser and LO cooler to and from the cooling tower.

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Boiler Tube Failure due to Opening a Drain ValveA wrong operational procedure leads to boiler tube failure and furnace damage. What went wrong? Read this to find out. This happened almost ten years ago. A simple but wrong operational procedure led to a catastrophic boiler failure and a repair that cost a few million dollars. We had just erected and commissioned a circulating fluidized bed boiler for an industrial plant in Southeast Asia. The boiler was a state of the art CFBC and almost the largest boiler in the region at that time. It was capable of

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producing nearly 400 tons per hour of steam for power generation and utility purposes, firing coal and biomass with superheated steam at a pressure of 140 bar and temperature of 540C. A basic understanding of a boiler is required to understand what went wrong.

FurnaceThe furnace of a modern boiler is made of welded tubes called membrane panels. The carbon steel tubes of diameter 60.3 mm welded at a pitch of 75 mm forms the boiler furnace with a height of 40 meters, width of 12 meters, and depth of 8 meters. The heat transfer area was around 1700 square meters. The heat in the furnace transfers to the water in these tubes to produce steam. The furnace is at temperatures in the range of 800C to 1000 C. The water flowing through the tubes keeps the tube metal temperatures well below the deformation temperatures. If there is no water flow in these tubes, the tubes will overheat and fail. This is true for any vessel that boils water. Even in your house, if you heat a pot or a pan without water it will twist out of shape.

CirculationHow does water circulate in these tubes? Water flows into these tubes from the boiler drum located at the top of the furnace through large pipes called "down comers." Steam starts forming in these tubes as it absorbs the heat from the furnace. The steam water mixture is at a lower density than the water in the down comers. Consider this like a U tube having the down comer filled with denser fluid (water) and the water wall tubes with lighter fluid (a water and steam mix). Both legs connect to the top drum. This density difference between the two legs causes circulation in these tubes.

BlowdownThe steam and water mixture from the water walls enter the drum, the steam separates, and the water recirculates back. The chemicals in the water do not evaporate and remain in the water. Continuous circulation of the water increases the concentration of the chemical content. Continuous removal of a part of the water from the bottom of the drum by a process called "blowdown" controls the concentration level.

DrainsThe water wall membrane panels connect to headers at the top and bottom. The down comers connect to the bottom headers distributing the water evenly to the tubes. The top headers connect to the drum through riser tubes that carry the water steam mixture to the drum. The bottom headers have drain pipes with valves. These manual operation valves are only for use during the initial operation for flushing and cleaning the headers or for filling or removing the water from the boiler.

The IncidentThe incident occurred during the final stages of commissioning. The unit was operating at near full load at the maximum operating pressure. Because of higher than allowable concentration of chemicals in the drum, the commissioning engineer decided to use the water wall drains for blowdown for a short time. Since these were manual valves operating under high pressure differential, the quick open-close operation was not quick enough. How long the valve was in open condition is unknown. This opening of the drains at the bottom headers had the effect of breaking the U tube effect and killing or reducing the flow of water through the tubes. This resulted in higher than acceptable metal temperatures in the water wall tubes. A few tubes failed, and the failure led to a unit outage. In the ensuing inspection, the extent of the damage was visible. The entire water wall on the front and sides of the furnace for almost the entire height was distorted into a wavy pattern.

RepairSince the plant was in an electrically islanded facility, the power and steam was necessary to keep the plant production levels. The boiler was back in operation after replacement of the burst tubes- at a lower load and pressure with the waterwall distortion. Because this was a CFBC boiler, the sand and ash circulating in the furnace required quick replacement of these wavy tubes before any failures due to erosion took place. The boiler operated with this condition for almost six months until the replacement tubes were available at site. It took thirty days to replace the walls and another fifteen days to put the unit back into service.

ConclusionOne should know the design basics and do some critical thinking before attempting to do something that is not normally done. ***************************************************************************************************

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Water Recovery from Power plant Flue GasCombustion of fossil fuels produces water, which is expelled as waste along with the flue gas. This article tells you how much water forms during combustion and how we can capture this water for utility purposes.

We never know the worth of water 'til the well is dry. Thomas FullerPopulation pressures, climate changes and deforestation are driving mans most wanted resource to scarcity. Let us explore one more way to augment this resource. When you burn fossil fuels or hydrocarbon fuels, the exothermic combustion reaction of Hydrogen in the fuel and Oxygen in the air produces water. This water goes out as vapour along with the flue gas. In coal firing, moisture in the coal augments the water quantity. The quantity of water produced is much more than the steam cycle make-up quantity in fossil fuel power plants. If one can economically capture this water and use it for steam cycle make up and other utility applications in the power plant, it can greatly reduce the pressure on regional water balances. This will be a boon for low rainfall regions and desert economies.

How Much Water?The combustion of hydrogen, the exothermic reaction, produces heat and water. The water quantity produced is almost nine times the weight of hydrogen. Bituminous coal contains around 3 % hydrogen which along with a 12 % moisture in coal produces almost 0.388 kilogram of water per kilogram of coal. A 500 MW plant consuming around 300 tons of coal per hour produces 116 tons of water per hour. Even with a fifty percent yield, a flue gas water recovery system can meet the steam cycle makeup water requirement. Natural gas contains 90 % methane which means one kilogram of natural gas produces almost two kilograms of water. A 500 MW gas turbine plant consuming 125 tons of natural gas per hour produces 250 tons of water vapor. The downside steam turbine cycle requires a make-up water of 50 tons per hour. A flue gas water recovery system with a fifty percent yield not only meets the steam cycle makeup, but also meets a part of the circulating water makeup. Fuel oil contains 13 % hydrogen, which means one kilogram of fuel oil produces 1.16 kilogram of water during the combustion.

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Three Methods to Capture the WaterCapturing water from flue gas may not be economical with current technology. However, developments and necessity will make it possible in the future. Combined cycle plants with cleaner and low temperature exhaust flue gas is the prime candidate for water recovery. When the requirement for capturing CO2 becomes mandatory, flue gas cooling will become a necessity. Integrating water recovery with CO2 capture will be the new power plant norm. Use heat exchangers to condense the water. Heat exchangers using plant circulating water, or as part of the steam condensate cycle, cool the flue gas to temperatures below the dew point, in the range of 40 C. The condensate collection augments the water source in the plant. Since the volume of the flue gas is very high, it may be practical to cool and capture water only from part of the flue gas.

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Additional cooling water, parasitic power, and capital investment are the main economic considerations. Removal of acidic constituents in flue gas like SO2 and NOx condensing at the 120 C range necessitates a two stage recovery. The first stage acidic condensate is sent to waste treatment. The heat exchangers are to be from acidic corrosion resistant materials.

Use a desiccant to absorb the water. Another method is to use a desiccant to absorb the water. Flue gas passes through a liquid spray in an absorber tower. The desiccant absorbs the water. Flashing releases the water and regenerates the desiccant. Cooling the vapors produces water. Cost of the desiccant, additional cooling water, parasitic power, and capital investment are the main economic considerations.

Use nano technology. This is the most promising method for flue gas water capture. Nano membrane tubes that allow permeation of only H2O molecules is the key. This is almost like a solid state system. This does not put undue pressure on auxiliary systems and can directly deliver water that is pure without any further processing. The nano membrane tubes are still in the development stage. Like the reverse osmosis membrane technology that is very popular today, higher production volumes will bring down the cost and make water recovery a reality.

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As technology develops, water recovery from flue gas will be an integral part of the thermal power plant cycle, making it more environmentally friendly. *************************************************************************************************** ***************************************************************************************************

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Chemical Recovery Boilers in Paper PlantsThis part of the article deals with the effect of various specific parameters of black liquor fired chemical recovery boilers. Black liquor is a unique fuel in boilers, and a brief account of its properties and effect on boiler operation along with feed water and air is discussed.

Effect of Various Parameters in Recovery Boiler OperationThis part of the series deals with the various parameters of the chemical recovery boiler that are different from conventional coal and oil fired boilers. As the combustion in black liquor fired chemical recovery boiler takes place under a reducing atmosphere, the effect of various parameters are critical.

Input parametersThe basic input parameters to the recovery boiler are: Black liquor quality which includes concentration (% dry solids), temperature, Higher Heating Value, composition, % organic to inorganic ratio, and other physical properties The feed water temperature and feed water chemical quality The combustion air temperature which plays a major role in bed stabilization

Black liquorThe important properties include liquor composition, total dissolved solids, ultimate chemical composition, specific gravity and density, viscosity, specific heat, thermal conductivity, boiling point, surface tension, calorific value, latent heat of vaporization and solubility characteristics. Other properties that are mostly qualitative in nature, and not genera,l and very often used for comparison purposes are precipitation point, swelling volume ratio, foam index, etc. Black liquor is distinctly alkaline (pH varies from 10.5 to 13.5), but not caustic owing to the fact that a large part of the alkali is present in form of neutral compounds. The lignin has intense black colour shading to reddish brown on dilution and retains a dark straw to yellow colour even when diluted to 0.04% with water. It is foamy at low concentrations. Black liquor from the sulfate process is generally foamier than that from the soda process. The foaming increases with an increase in resin content of wood used for pulping. The amount of total solids in black liquor depends on the quantity of alkali charged to the digester and the yield of pulp. Under average conditions, black liquor going to evaporators will contain 14-18% solids for wood and bamboo. In general, the inorganic compounds in black liquor tend to decrease specific heat and thermal conductivity, increase density, specific gravity, viscosity, boiling point elevation, and have practically no effect on surface tension. The organic constituents of black liquor tend to decrease specific heat, thermal conductivity, and surface tension, and increase density and viscosity values. The data also shows that there are considerable differences among values for the different liquors attributed to the diversity of organic constituents in black liquors caused by the variation in pulping species, pulping conditions, and pulp yields. The black liquor obtained from agricultural residues, wheat straw, rice straw, and bagasse, etc. are characteristically different.

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Black liquor generally contains 50%-70% organics and 30%-50% inorganics. It also contains minor amounts of impurities such as lime, iron-oxides, sodium chloride, and alumina. High silica content is a major obstacle in any recovery process. The concentration of silica is particularly high in rice and wheat straw black liquors. The presence of silica leads to problems related to scaling, clarification, and precipitation. The non-wood fiber black liquors have a high percentage of silica: 4 - 6% (even more) in case of straw and 1.% in case of bagassee. Silica enters both as intrinsic and external silica with raw material and cooking liquors. The magnitude of silica for different liquors is: rice straw 3 - 16%, wheat straw 3 - 6%, bamboo 2 - 5%, bagasse 1 - 3%, and eucalyptus 0.1 - 0.8%. *************************************************************************************************** ***************************************************************************************************

Cleaning High Pressure Boiler Internal SurfacesHigh pressure boilers need very clean internal surfaces. The pre-commissioning cleaning involves Alkali boil out to remove any oily materials, Acid Cleaning to clean up mill scales and Steam blowing to clean superheaters, reheater, and piping. Post-commissioning cleaning is specific to each boiler. High pressure boilers are designed to produce steam at a specified quality. Improper steam quality can lead to tube failures in the boiler, as well as turbine blade damage, resulting in large availability loss. The cleaning of internal surface of high pressure boiler can be grouped into two main methods, one pre-commissioning and the other postcommissioning cleaning.

Pre-commissioning cleaningDuring manufacturing of seamless steel tubes, a quantity of mill scales are bound to be formed, and some of these can remain inside. During fabrication and erection of the pressure parts, some amount of oil and grease can also get into the tube surface apart from the weld slag and other materials. Taking all of these into consideration, the precommissioning cleaning has three major steps. Alkali boil out - which is for removing the oil and grease from the internal surface. Acid cleaning - for removing the mill scales in the internal surface. Both acid cleaning and alkali boil-out are done for all water-touched surfaces. Steam blowing - In the case of super heaters, reheaters, and steam pipes, they are cleaned by steam blowing.

Alkali boil-outThis operation in boilers is taken up after hydraulic testing of the boiler is completed and the oil burners are commissioned. Alkaline flushing is carried out before the boiler is taken for alkali boil out. It is a practice to mechanically remove the oil and grease wherever possible. The drum internals are installed before start of alkali boil out. Normally sodium carbonate and sodium phosphate in equal quantity along with a detergent to about 0.05 to 0.1% by volume are used for alkali boil out.

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After the boil out solution is added, the drum level is checked though a gauge glass and confirmed before firing the boiler. The boiler is brought to 20 kg/cm square in about 8 hours time keeping in mind the rate of pressure raise and temperature raise allowed for cold startup. The drum level is maintained at normal level during this operation. After about four hours at pressure, the fire is shut down and the boiler is allowed to cool. This ensures the sludge settle down and the boiler blow down is carried out using the bottom drain. Care should be taken to maintain the drum water level with in the visible range of gauge glass. This operation is done for four times to a total of about 16 hours. Solution samples are taken at regular intervals, and if the original concentration drops to half or below, chemicals are added to bring back the concentration. The boiler is then drained after the drum metal temperature is below 90 degree C. The boiler is then rinsed with clear rinse water and flushed.

Acid cleaningMany methods are used by different boiler makers to clean the mill scale and rust inside the tube surface. It is very important that this operation is carried out by an experienced and reliable agency. The methods used are circulating acid method and soaking method. In the case of the circulating method, external acid cleaning pumps are used to keep the acid in circulation. However in the case of soaking method the acid is kept stationary for a specified time. Many combinations of acids are used for this purpose. The most popular acid is 5% hydrochloric acid with inhibitors that are used to inhibit the action of acid on the cleaned surface of the tube. The super heater tubes should be plugged and water filled and maintained under positive pressure so that the acid vapors do not enter the tube surface. The boiler is drained under nitrogen at a positive pressure; this is needed to protect the internal virgin surface. The sludge resulting from mill scales and rust will have to be flushed from the bottom headers. The boiler then goes though a passivation operation to ensure a protective layer formation inside the tube surface.

Steam blowingSteam blowing is used to clean the super heater coils and the steam pipes like main steam and reheater pipes. There are two methods used for steam blowing: continuous blowing and intermittent blowing. In both cases, the idea is to create a disturbance on the surface of the tube or pipe well above that is possible during the peak load operation of the boiler. It is seen that at a pressure of around 40 kg/cm squared, the internal surface of the super heater and steam pipes are subjected to such a disturbance that any loosely adhering material is dislodged when the steam is allowed to blow out to the atmosphere. The completion of steam blowing is declared if the target plate of turbine blade material kept at the predefined point is free from any indentation or is within allowed limits. To complete the steam blowing in super heater, reheater, steam pipes, etc, steam blowing is done in more than one stage.

Post-operational cleaningDuring operation boilers accumulate deposits inside the tube surface depending upon the quality of water chemistry maintained. Once the boilers have operated for about five years then it is a good practice to take tube samples from the high heat flux region and evaluate them for internal deposit. The samples are taken from all the four walls of the boiler furnace walls and tested for the amount of deposit and the chemistry of deposit. If the deposit quantity is above 40 mg/cm squared, then the tube is termed dirty and acid cleaning is recommended. The type of acid to be used for cleaning will depend upon the chemistry and adherence of the deposits to the tube surface. If the deposit contains copper from the pre-boiler system, then this has to be first removed. The other ingredients of the deposit are removed subsequently. Hence the post operational cleaning can have a few stages of acid cleaning. To decide this, tube samples taken are subjected to a cleaning test in the lab using the actual acid, temperature, time and stages planned at the site. Based on the results of the cleaning in the lab and result there achieved, the final recommendation is given to the boiler owner. *************************************************************************************************** ***************************************************************************************************

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Electric Power Generators- How They WorkElectricity is the most convenient form of energy. Like the genie from "Aladdins Magic lamp," at the flick of switch electricity is ready to do anything at the master's bidding. How do we generate this genie, electricity? What are the defining characteristics of the electricity we use? Nothing is too wonderful to be true if it be consistent with the laws of nature. Michael Faraday

HistoryThe principle of electromagnetic induction is the basis of the generation of electricity. Discovered in 1830 by Michael Faraday, this later led to the development of the dynamo by Pixie. This started the generation of electricity by converting mechanical energy from steam turbines and hydro turbines. Be it the generation of a few watts of electricity or millions of watts (mega watts) of electricity, the basic principle remains the same.

The Basics of GeneratorsIn its simplest form the electric generator consists of A magnet that produces a magnetic field. A movable copper conductor placed at right angles to the magnetic field,

When the copper conductor moves, the conductor cuts the magnetic field. This produces an emf (electromotive force) or voltage, which sends an electric current through the copper conductor. Mechanical energy moves the coil converting it to electrical energy.

Modern Electrical GeneratorsIn real life, the electric generator is slightly different. The magnet is an electromagnet and it rotates. This is the 'rotor' or the 'field' and consists of wound conductors on the rotating part of the generator. The copper conductor is stationary called the ' stator' or the 'armature'. This consists of high current carrying copper coils wound on the stationary part of the generator. The rotor's rotating magnetic field cuts the stationary stator copper conductors to produce the electric current. The energy for rotation of the rotor is from a rotating turbine or an Internal Combustion engine.

All generators use this basic principle. Only the primary energy source and prime mover is different. The prime mover can be a steam turbine, a gas turbine, a wind turbine, or a hydro turbine. One very important factor about electric generators is their synchronised operation.

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All the power plant generators connect to the national or the regional transmission grid. The domestic, public, or industrial users get the electricity from this grid. This means all these generators should produce electric power that has the same characteristics.

Three characteristicsThe three important characteristics are Frequency: The power what we get is an alternating current with 50 Hz, which very simply means the voltage and the directional flow of the electric current changes 50 times a second. In the US, Japan, and some other countries the frequency is 60 Hz. Even though this is something we cannot see or feel this is a very important in the design of and operation of electric generators and appliances. Voltage: this is the main electromotive force that drives the electric current. Large generators produce electricity at 20,000 volts, smaller generators output at 400 volts or 6000 volts. These voltages are "stepped up or down" as required for transmission and distribution to the user. Transmission of electricity over large distances takes place at very high voltages in the order of 150,000 to 400,000 volts or more. A domestic user needs electricity at 230 volts (120 volts in US). Even though the different types of generators produce voltages at certain standard levels, at the connection point to grid they all have to have the same equivalent voltage. Phase: Large electric power generators produce 3-phase electric power. Very simply put this means there are three different circuits each generating power at the same voltage and frequency. The only difference is the highs and lows in each circuit takes place at different times in each of the 50 Hz cycle. The advantage is the electric current through each conductor is one third of that of a single phase making it very cost effective in transmission and application. In addition, it is easier to produce a magnetic field required to run an electric motor. Household appliances work only on a single phase, but almost all of industrial application at higher loads use three phase.

While connecting a generator to the grid it is very important that these three characteristics match with that of the grid to which it is connected. If not properly done this can disastrously damage the generator. The process of connection is known as synchronisation. *************************************************************************************************** ***************************************************************************************************

Bank Tube Failures in Bi-drum BoilersBank tubes in bi-drum boilers act as raisers and down comers between the two drums. They also carry the load of the bottom drum and its down comer. Failure in these tubes needs to be attended depending upon the type of failure and the location of failure. Bank tubes are used to connect the upper drum and lower drum in bi-drum boilers. These bank tubes not only act as raisers and down comers between the drums but also carry the weight of the bottom drum and the down comer of the bottom drum. Any failure of these tubes results in damage to the nearby tubes or drum or both, depending on the location of the leak. Attending to these failures require special care and methods. These joints are mechanically held by the expansion of the tube in the drum holes. The tube deforms to a plastic condition and the drum hole, being in elastic condition, exerts the required sealing force for the joint against the drum operating pressure. It is seen that an expansion resulting in about 7 to 11 % thinning of tube thickness results in a good joint. Normally these joints are more effective for pressures up to 120 kg/cm2. Tube wall thinning can be calculated by knowing the tube ID before and after expansion.

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D1 = Tube ID before rolling when the tube OD just touches the drum hole. This is achieved after light rolling and is called touch rolling; not much torque will be required for this. Once the tube OD touches the drum hole ID, the expander torque will increase indicating the tube has touched the drum hole ID. D2 = Tube ID after rolling T1 = Tube wall thickness before rolling. Note: Even at touch roll point the thickness of the tube is the same as that before starting touch expansion.

Percentage thinning = 50 x (D2 - D1) T1There is also a practice to measure the thickness before and after expansion and calculate the percentage of thinning. However it is my experience and opinion that measuring tube ID is more reliable after expansion. Hence I always prefer to use the diameter method.

Reasons for bank tube failure The main reason for bank tube failure due to expanded joint failure is inadequate expansion. Many times it is very difficult to measure each tube ID for checking the percentage thinning, hence it is a practice to measure a few tubes in every 100 or 200 tubes and fix the expander torque to get the required thinning. This torque is applied to the tubes and is taken for granted that the expansion is achieved. This is true only if proper lubrication is done on the expander rollers so that minimal torque is lot in friction and the thinning is achieved. Expanded joint also fails due to thermal shock created due to large number of start-ups and shut downs in a short span; say 50 start-ups and shutdowns in about ten to twenty days. Internal deposits leading to long-term overheating failures Blockage leading to short term overheating failure Erosion and corrosion of tube surface

Attending to the bank tube failure mainly depends on the type of failure and the intensity of the failure. In case of expanded joint leakage resulting in puncture of the tube, generally it is the practice to plug both ends of the bank tube in top and bottom drum. This is mainly due to the reason many a times it will not be possible to reach this tube location without removing large number of tubes. Plugging tubes should not be adopted if locally there are many tubes to be plugged. This can cause problem in other tubes nearby. Plugging is adapted to other type of failures when approach is not there without removing many bank tubes. No spool piece welding is to be done on bank tubes as this can cause failure in the expanded joint. When the failure reason is established as low expansion carried out, then re-expansion has to be done in all the tubes. It is always better to restrict the thinning of the tube thickness to a maximum of 15 to 18%. Above this you will see that the tube material start flaking and lead to brittle failures. Seal welding of bank tubes is permitted after expansion. All precautions are to be taken during welding not to deviate from the welding procedure as any welding on drum has to be done with the utmost care. It is required to lightly re-roll the seal welded tubes and do not flare the tube end.

Replacing all the bank tubesThere are times when all the bank tubes need changing. The procedure will have to be carried out by an expert group knowing all the implications while carrying out this. Since the entire bank tubes are to be replaced, The bottom drum has to be properly supported before removing the old bank tubes After removing the bank tubes, each hole in the drums (steam and mud drums) has to be checked for its required dimension and for any damage before replacement of the tubes

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For enlargement/ovality in the holes, the normal tolerance limit for acceptance is (d+0.032 ) + 0 / 0.015 ; where d is the outside diameter of the bank tube If due to steam or water erosion the hole size is more than the limit, then weld build up has to be carried out to get the required size with suitable preheating and post heating. After getting the required hole size, the insertion and subsequent expansion of the bank tubes have to be carried out in proper sequence If seal welding is carried out with suitable electrode and with required preheating. Do not weld the bank tube directly to the drum without achieving required expansion on the bank tubes, and no strength weld is allowed in this area.

Related ReadingBoiler tube failures are inevitable. There are twenty-two primary reasons for tube failures in a boiler. It is true that being forewarned is being forearmed. Knowledge and good operating and maintenance practice reduce tube failures. As carbon emission is a major concern today, more super critical pressure units are bound to be preferred due to the increase in plant cycle efficiency. This will make once through type boilers take over from drum type boilers . *************************************************************************************************** ***************************************************************************************************

Wall Blowers Optimization in BoilersThere are many methods used for optimization of wall blower operation in boiler furnace, like the manual method, heat flux measurement method, and the automated method. The manual method is discussed as this will bring out the philosophy involved in optimizing wall blower operation. Wall blowers are provided in boilers to clean the furnace wall deposits. They seldom finds use in oil and gas fired boilers. The deposition and slagging in boiler furnace is required to be removed from the furnace walls at regular intervals. The interval period will depend on the area of deposition and the severity of deposition. Steam wall blowers are found to be very efficient in removing the furnace wall deposits. However, the steam wall blowers are not at all effective in the case of molten slag removal from the furnace walls. Water lancers, instead, are used for molten slag removal. In a large boiler of around 1500t/hr capacity, the total number of soot blowers can be around 120. In this, around 90 numbers will be wall blowers. The frequency of soot blowing will depend on the type of coal being fired. However the operating group must remember that the initial suggested sequence and frequency is more general and has to be adapted to each boiler. The purpose of these soot blowers is to keep the heat transfer surface clean so as to contribute towards optimal performance of the boiler.

Effect of the wall blower on boiler performance Removes the deposits on the furnace wall and ensures good heat transfer in the furnace region The furnace outlet temperature slowly ramps up after wall blowing as time lapses Superheater spray quantity is seen to increase with time lapse after wall blowing Increases the bottom ash quantity depending upon the deposition on furnace walls Increases furnace tube material loss if blowing is done too frequently without any deposits. This leads to boiler outage or increased maintenance. In the case of water lancers for removing molten slag, while operating there will be a large dip in generation for the same heat input. This is mainly due to the increased boiler losses.

Optimisation of wall blowers

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Before taking up wall blower optimization, the following will have to be ensured. All wall blowers are set to the right steam pressure recommended by the designer Check the alignment of the wall blower with respect to the furnace walls Ensure at least 50 degree centigrade of super heat in the steam being used. This is to prevent damage of the furnace walls due to wet team impingement. All wall blowers are operational It will be of great help if the boiler furnace walls are photographed just after a planned shutdown. Before shutting down the boiler, do not wall blow the furnace for one full sequence. This will ensure deposit collection on the walls between the adopted frequency. While shutting down the boiler ensure minimal thermal shock, by slowly lowering the load. This will ensure deposits stay on the walls. Take the photograph from a convenient man hole. But take all safety precautions as anytime the deposit can fall down due to cooling or thermal gradient.

There are many methods used for optimization of wall blower operation, like the manual method, heat flux measurement method, and the automated method. The manual method is discussed as this will bring out the philosophy involved in optimizing wall blower operation.

Need for wall blower optimization To improve consistency in efficient operation of boiler To reduce steam wastage by identifying those areas of low or no deposits To reduce damage on furnace wall tubes due to excessive blowing

The change in SH spray without change in other parameters indicates that the furnace deposits are increasing. If the superheater spray increases above a particular level (to be determined for each boiler) operate wall blowers. These are two basic things to adhere to while optimising wall blowers.

Steps in wall blower optimisationAssuming there are 88 wall blowers in a boiler furnace wall, the steps for optimisation is listed. Operate all 88 blowers See the effect on superheater spray and note all operating parameters of boiler Wait for the superheater spray to ramp up to the initial level and stay almost steady Wall blow each row - study effect Watch superheater spray drop and regain time The interval between blowers is to be maintained constant Repeat if required each row independently, waiting each time for the spray to reach the original level with other parameters of boiler remaining constant Repeat the study for two adjacent rows Repeat the study for two alternate rows Repeat the study for blowers in front, rear, left and right sides of furnace walls separately and study the effect on superheater spray flow. The blowing having the least effect on the superheater spray indicates low or no deposit on the walls. A plot of superheater spray drop when each blower is operated will give a good idea of deposition in that area Use the photograph of the furnace wall to validate the effectiveness of blowers Decide which blowers can be skipped during blowing as well as the effectiveness of the row

The procedure for wall blower operation can be evolved after the study and data analysis for the most effective way of wall blowing.

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The use of heat flux meter by embedding thermopiles at appropriate location in the furnace walls to understand whether the tube in the region is clean or with deposition the operation of the wall blower requirement can be decided. In the case of fully automated intelligent wall blower system, the need to wall blow each blower is understood from the effective heat flux falling on the tubes. Designers use different methods to establish this. *************************************************************************************************** ***************************************************************************************************

Considerations for Coal Blending in Power StationsCoal blending in power stations is mainly adopted to reduce the cost of generation and increase the availability of coal. The low-grade coals can be mixed with better grade coal without deterioration in thermal performance of the boiler, thus reducing the cost of generation. In many nations, the blending of high grade imported coal with low grade high ash coals has long been adopted. Many methods may be used. The blending can occur at the coal mine, preparation plant, trans-shipment point, or at the power station. The method selected depends upon the site conditions, the level of blending required, the quantity to be stored and blended, the accuracy required, and the end use of the blended coal. Normally in large power stations handling very large quantities of coal, the stacking method with a fully mechanized system is followed. To decide to blend or not, it is very important to understand the composition of the coals that are to be blended. This means one will have to understand the origin of coal, the organic and inorganic chemistry of coal, and the behavior of the coals in questions. It has been established that coals produced by the drift theory of coal formation and coals formed by the swamp theory of coal formation have to be blended with caution. The main difference is that coal formed by drift theory exhibits pronounced regional variation in thickness and quality of seams. They also have enormously high ash content with varying inorganic chemistry. The organics of drift origin coal also present problems mainly because the vegetation that lead to the forming of the coal drifted from different places having different kind of vegetation. In contrast, the coals formed by the swamp theory have much more uniform organic properties and much lower ash content with consistent inorganic chemistry. During combustion, it is necessary to understand the physical conditions and coal properties during heating of the particles, devolatalisation, ignition and combustion of the volatile matter, and ignition and combustion of the char. It is also equally important to know the phase changes in mineral matter and other inorganics present in coal. The combustion efficiency and carbon loss will have to be also addressed during blending of coals. It is also necessary to look into the aspects of slagging, fouling, and emission characteristics like NOx, Sox, and particulates. Because of the complexity of the combustion process and the number of variables involved (which are still not fully understood), it is difficult to extrapolate small scale results to a full scale power plant. Thus, operational experience with a wide range of plant configurations with a variety of coal feedstock is essential for determining the practical significance of results from bench and pilot scale tests. More published research about how the behavior of the coals and coal blends utilized in tests differ from their actual performance in power station boilers is required. Predicting the risk of spontaneous combustion of coal stocks is another aspect of current fuel quality research. In addition to the inherent dangers, uncontrolled burning can lead to the release of pollutants. The economic issues associated with the loss of a valuable energy resource are also a concern. For more basic information, read about how coal power plants generate electricity by burning coal and find some other interesting facts about the process.

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The presence of trace elements in coal combustion has also received increased attention throughout the world during the last few years, with elements such as mercury of particular concern. One way to reduce trace element emissions is cleaning the coal prior to combustion. The use of cleaner coals those with lower ash and sulfur content can have the added advantage of substantially reducing operating costs. Again, however, some effects may be detrimental (ash deposition may be exacerbated, and the effects on corrosion and precipitator performance are uncertain), which makes testing vital. It has been found from field data that even if the blended coal closely resembles the design coal for the boiler, the blend need not perform the same way. This is mainly due to the transformation of inorganic particles during combustion and the way in which the organics are dispersed in coal. A limitation to blending coals is the compatibility of the coals themselves, and problems are more likely when blending petrographically different coals or coals with different ash chemistry. Non-additive properties make blend evaluation for power generation inherently complex. More work is required on understanding how the inorganic components of coals in the blend interact and how it affects ash behavior including its emissivity, reflectivity, and thermal conductivity. Blending decisions should be based on the knowledge of the specific behavior of a given pair of coals, rather than an assumption of linear variation of properties with blend traction. The ever more stringent constraints placed on coalfired power stations worldwide and the continuing development of new technologies means that the issue of fuel quality improvement will remain a primary factor. *************************************************************************************************** ***************************************************************************************************

Cold End Corrosion in a Boiler and Its PreventionUsing fuels with sulfur in steam generating units yields a potential hazard of sulfur corrosion at the cold end of the boiler. The severity depends on many factors like percentage of sulfur in the fuel, excess air, moisture in flue gas, etc. Many options are available to contain cold end corrosion Boilers generating steam for use in power generation and process power plants use different type of fuels. These fuels contain sulphur to differing percentages. The higher the percentage of sulphur, the higher will be the risk of cold end corrosion in the boiler. The sulphur in the fuel during combustion gets converted to sulphur dioxide. Depending upon the other impurities present in the fuel and excess air levels, some portion of the sulphur dioxide gets converted to sulphur trioxide. The presence of moisture in the flue gas due to moisture in fuel and air, sulphur dioxide, and trioxide, combines with moisture and forms sulphuric acid and sulphuric acid. These acids condense from around 115 degree centigrade to slightly higher than 160 degrees, depending upon the concentration of SO3 and water-vapour. The basic reactions taking place are

S + O2 SO2 SO2 + O2 SO3 H2O + SO2 H2SO3 H2O + SO3 H2SO4Depending upon the ppm of SO3 and water-vapor concentration, the dew point temperature can vary from around 90 degree centigrade to 140 degree centigrade. Condensation of these acids results in metal wastage and boiler tube failure, air preheater corrosion, and flue gas duct corrosion. In order to avoid or reduce the cold end corrosion the gas temperature leaving the heat transfer

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surface in boiler is kept around 150 degrees centigrade, ranging from 120 to 155. It is very important that the metal temperature of the tubes is always kept above the condensation temperature. It may be noted that the metal temperature of the tubes is governed by the medium temperature of the fluid inside the tubes. This makes it necessary to preheat water to at least 150 degrees centigrade before it enters the economizer surface. In the case of an air pre-heater, two methods are used to increase the metal temperature. One is an air bypass for air pre-heater, and the second is using a steam coil air pre-heater to increase the air temperature entering the air pre-heater. The amount of SO3 produced in boiler flue gas increases with an increase of excess air, gas temperature, residence time available, the amount of catalysts like vanadium pentoxide, nickel, ferric oxide, etc., and the sulphur level in fuel. The flue gas dew point temperature increases steeply from 90 degree centigrade to 135 degrees centigrade with sulphur percentage increasing up to 1%. A further increase in sulphur percentage in fuel gradually increases the dew point temperature from 135 degree centigrade to 165 degrees centigrade at 3.5% sulphur in fuel.

Prevention of cold end corrosionThere are many methods used world over to contain cold end corrosion. These methods fall in the category of incombustion reduction and post-combustion reduction. The in-combustion reduction methods include: Burning low sulphur fuel Low excess air burners Fuel additives Fluidized bed combustors

Going in for low sulphur fuel sometimes become economically unviable for the process for which the steam generators are used. Today many low excess air designs are available in the market. These burners adopt many ways to reduced excess air requirement without affecting the unburnts in the flue gas after combustion. Fuel oil additives like simple magnesium oxides are used to contain cold end corrosion due to sulphur. The magnesium oxide is injected in to the furnace or mixed with fuel which combines with sulphur oxides to form magnesium sulphate. In fluidized bed combustors, lime addition is a simple method used to reduce sulphur corrosion. The post-combustion technologies adopted are: Designing with higher exit gas temperature Air bypass across air pre-heater Ammonia injection Flue gas desulphurization (FGD)

Designing boilers with higher exit gas temperature reduces the boiler efficiency. As a rule of thumb approximately every 20 degree centigrade increase of flue gas temperature at boiler outlet reduces the efficiency by 1%. Hence this is not a preferred method in the present days. Air pre-heater bypass is for mainly for startup purposes until the metal temperature can be maintained above condensation temperature even when the cold air enters. Some designers use steam coil air pre-heater for full operation of the boiler. Ammonia injection was a method adopted by a few designers in certain process plant boilers burning high sulphur oil due to the availability of ammonia. Ammonia is injected in the economizer region where the temperature of flue gas is below the ammonia dissociation temperature and sufficient time is available for the chemical reaction. Ammonia combines with sulphur trioxide to form ammonium sulphate. The rate of ammonia injection will depend upon the SO3 concentration. The problem with this method is it produces a high volume of loose deposits of

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ammonium sulphate, which increases the pressure drop in the flue gas path. Removal of these deposits is done by water washing of the air pre-heater online. Flue gas desulphurization is a very common method adopted in the present day. Here the flue gas with acid vapors is scrubbed to remove it as a byproduct. Most of the FGD processes use alkali to scrub the flue gas. Many designers of FGD adopt the limestone gypsum process. This process has gained acceptance due to the saleable gypsum byproduct. Sea water availability makes it possible to use it as an absorbent of sulphur oxides in acid form. There is another process called the Wellman-Lord Process, which is a regenerative process that uses aqueous sodium sulphite solution for scrubbing flue gas. The saleable byproduct, depending on the plants design, could be elemental sulphur, sulphuric acid, or liquid SO2. There are many working plants using this technology in Japan, USA, and Germany. The Sodium Bicarbonate Injection Process is a direct injection method adapted to de-sulphur the flue gas. Here the sodium bicarbonate is injected in the duct after the air pre-heater and before the dust removal system like an electrostatic precipitator or bag filters. *************************************************************************************************** ***************************************************************************************************

Using Coal Petrography for Combustion Problem SolvingPetrographic analysis can give useful information about the combustion of pulverized coal. Petrographic analysis of coal has been used to evaluate the efficiency of a pulverized coal fired boiler since 1968.

What is Coal PetrographyThe discipline wherein coal is studied as a rock consisting principally of macerals is called coal petrology (Petro: rocks; logy; the science of) and the description or classification of coal as a rock is referred to as coal petrography. Coal is not a uniform mixture of carbon, hydrogen, oxygen, sulphur, and other elements; nor is it, as is often implied, simply a uniform polyaromatic substance. Rather it is an aggregate of microscopically distinguishable, physically distinctive, and chemically different substances called macerals and minerals. The study of coal maceral constituents based on the structure is important to know the coal type. Two basic systems of petrography have been used over the years, the Stopes-Heerlen (SH) and the Thiessen Bureau of Mines systems. The former, almost universally now accepted, was developed by Marie C Stopes, a British Coal Scientist. The nomenclature system of Stopes began by her description of the different components of coal visible to the unaided eye, called litho types or rock types. Later, she revised her system of nomenclature to include components visible by microscopic examination of polished section of coal in reflected light. The term macerals was suggested for these microscopic components of coal, in analogy to minerals in rocks.

Microscopic Identification of MaceralsMacerals are microscopically identifiable components. The coal under study is powdered, mixed with binder, formed into a block and polished. These blocks are looked at through a microscope to study the structure and reflectance. Depending upon the structure and reflectance of the macerals, it is classified into different categories. The total macerals in coal can be broadly grouped into two major categories, namely the reactive and inert. The reactive group consists of the Vitrinites and Exinites and the inert group has Inertinites. With increasing percentage of inertinites, the coal properties like combustion or gasification reactives deteriorate very much. This is true both in the case of coking and non-coking coals. Mineral matter in coal is generally classified as inherent or extraneous. These are present in coal in addition to purely organic substance. Both macerals and the microlitho types contain small or larger amount of inorganic components.

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The petrographic composition affects the ignition process, combustion, and the efficiency of combustion. Maceral types and reactivity need not have simple relations, all inertinites are not inert and not all vitrinites are reactive. The reflectance values of the maceral groups and the association of the different macerals, determined as micro lithotypes also need to be taken into account. Mineral matter also affect the type of char formed, and the situation gets further complicated by different char characterization. Pulverised fuel combustion is used widely in power plants for the generation of electricity. Selection and testing of coals is an important factor for the efficient operation of boilers, and many different tests are carried out for this purpose. Coal petrography has gained importance in order to understand how combustion behaves from the fuel side. Changes occurring during pyrolysis determine the morphology of the char and the char types present affect the overall combustion efficiency. The type of char formed can depend on the macerals present, the rank of the coal, the particle size, and the temperature of char formation. The main influence on char formation is associated with the organic part of the coal. The presence of certain types of minerals can affect the type of char formed. Reactivity can also be influenced by mineral matter. Vital properties such as flame stability and burnout efficiency can be affected by the presence or absence of certain minerals. Even though it is evident that mineral matter adversely affects complete combustion, the total removal of mineral matter is impractical and is also undesirable as regards the requirements of modern burners. These inorganic compounds can be classified into four groups according to their origin: Inorganic matter from original plants Inorganic - organic complex minerals formed due to inorganic and organic interaction during the first stage of coalification process. Minerals introduced by water or wind into the coal deposits as they were forming. Minerals deposited, during the second phase of coalification process after consolidation of the coal, by ground water solutions in cracks, fissures, or cavities by alteration of primary minerals.

Many variables affect complete combustion including temperature, oxygen level, residence time, and char morphology (mainly structure, porosity, density, and optical texture). Some workers clearly state that vitrinite chars are more reactive than inertinite chars. Vitrinite char has been estimated to burn two to four times as fast as inertinite char. Some semifusinite has been found to ignite before vitrinite and burn faster. The rank of a coal can be expressed by the reflectance of the vitrinite, which is related to C H and C/O ratios and volatile matter. The use of rank appears to be the most accurate means of predicting combustion behaviour. *************************************************************************************************** ***************************************************************************************************

Combustion Tuning in High Ash Pulverized Coal Fired Boilers having Direct Tangential Firing SystemCombustion tuning in boilers will lead to optimizing the performance more so in high ash coal fired boilers. In high ash coal fired boilers having direct tangential firing systems, proper combustion will ensure minimum water wall deposits and thus an optimal furnace outlet temperature.

Pulverised coal combustionPulverised coal combustion involves two main sequential, but possibly overlapping, stages. (1) Rapid heating and devolatilisation as a result of pyrolysis followed by (2) combustion of char residue emanating from the

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devolatilisation stage. The first stage is fast, taking times in the order of 0.1 sec. only. The second stage is slow, requiring times in the order of 1 sec. to 2.5 sec. and therefore, thus has a major effect on the size of the combustion chamber. In practical combustion situations, such as in a large pulverized coal combustor, different particles can undergo concurrently different processes such as pyrolysing, oxidising reactions under different temperature regimes.

Tangential firingIn a tangential firing system the coal is pulverized in coal mills and is carried by primary air to the furnace through coal pipes. The mills are usually a constant airflow mill and have a specific output in mass of coal ground depending on coal properties like hardness, moisture, and fineness which affect the mill output. In direct tangential firing systems, the pulverized coal from the coal mills is directly taken to the furnace. Coal properties such as FC/VM (Fixed Carbon / Volatile Matter), particle size, oxygen, calorific value of the coal, reactivity, and ash content seem to be the most important variables for pulverised coal combustion in tangentially fired boilers, and they are highly inter-related. The total quantity of coal to be pulverized for a specified size of boiler at a designed efficiency will depend on the calorific value of coal. As the ash content in coal goes up, the calorific value per unit mass of coal comes down. This increases the mass of coal to be prepared, which in turn increases the number of mills or elevations needed in a tangential firing system. The secondary air required for combustion is sent into the furnace through a windbox housing the coal nozzles, oil guns, and the secondary air nozzles. Behind the coal nozzles there are fuel-air dampers which are used for keeping the flame front away from the coal nozzles by at least one meter from the tip. This is required to prevent the coal nozzle tips from getting burnt due to radiation from coal flame. The flame front is predominantly affected by the volatile matter in coal and the fuel air damper is modulated for controlling the flame front. As the fuel air dampers are opened, more secondary air goes through this damper and physically pushes the flame front away. However, when the flame front is already away from the nozzle tip, the fuel air damper needs to be closed fully.

Combustion airThe total air quantity for combustion in a boiler will depend upon the million kilocalories being fired to generate steam at a specified parameter. This total air is divided into primary air and secondary air in the ratio of 30 % and 70%. As the ash percentage goes up in coal, the amount of mill air flow goes up, as the number of mills to be in operation goes up. This results in an upset between primary and secondary air ratio. Tuning combustion in high ash pulverized coal fired boilers having direct tangential firing systems should address all the above said factors.

Combustion tuning steps Operate the boiler at a constant load and designed steam parameters Keep the excess air around 20 to 25% Load all the mills equally and keep only the minimum number of mills required Adjust the mill fineness to the required level normally 75% through 200 mesh and less than 2% on 50 mesh sieve Keep the mill outlet temperature close to 85 to 90 degrees centigrade Adjust the mill air flow to just above the settling velocity o Note the operating mill air flow reading and reduce the mill air flow in steps of 0.5 to 1 t/hr wait for a minimum of 15 minutes before reducing again o Watch the furnace draft while doing this, when a small fluctuation starts then stop reducing the air flow and note the reading o Increase the air flow above that was being maintained before reduction and keep it for 30 minutes this clears off any settling in the coal pipe

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Now keep the mill air flow at the flow value noted when furnace fluctuation started plus about 1 t/hr, make sure no furnace pressure fluctuation is seen o Repeat this for all the mills one by one This ensures minimum primary air flow being used for transporting the high ash coal powder to the furnace Check the flame front if it is one meter away from the coal nozzle tip then close all fuel air dampers. If volatile matter in coal is 20% or less this condition gets satisfied Keep the windbox pressure of 80 to 100 mm of water column Watch the furnace for the flame conditions like brightness and flickering

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The steps carried out will help to achieve combustion at optimal level. Optimum combustion in the boiler will ensure performance of the boiler within a desired limit. *************************************************************************************************** ***************************************************************************************************

System Levelised Energy CostFor the investment analysis and fixing cost of energy for the different electricity generation scenarios the Levelized Cost of Energy method is used. Why do we require this method? How to calculate the Levelized Cost? Read more... Energy conversion to electricity can be in many ways. From the most common coal fired plants to the renewables like solar and wind, the methods are many. The investment pattern and the return on investment for each method is different making it difficult to compare cost and evaluate investment strategies. The initial investment required to construct a coal fired power plant is comparatively less, about 1000 $/kW. But the operational cost, mainly the cost of fuel, is very high which continues during the life of the plant, say twenty or thirty years. Also the fuel cost will be subject to escalation. The same is the case with a gas turbine power plant. The fuel prices are subject to high escalation costs. On the other hand a nuclear power plant requires a very high investment, in the range of 3000 $/kW. But in the long run the fuel costs are considerably less. In the case of a solar power plant the initial investments are high, in terms of land area and equipment. The output energy units is very low only 12 to 20 % of the installed capacity, even though the input energy cost is zero. Wind, hydro and geothermal power plants also require high initial investment, but considerably lower operational costs. Also many renewable energy projects get government incentives. Today carbon capture costs are also a consideration for investment analysis.

These are some of the very different scenarios in power generation investment. How to compare and calculate the economics of each type of power generation? How to arrive at a cost to charge the consumer? The Levelized Cost of Energy (LCOE) is the method that is commonly used. The method can also compare different technologies competing for a utility bid. Utilities use this to calculate the electricity cost to be charged to the consumer. In the electricity bidding market this LCOE is a very important factor.

What is Levelized Cost of Energy?Very simply put this is the sum of all the costs incurred during the lifetime of the project divided by the units of energy produced during the lifetime of the project, expressed as $/kwhr.

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Since most of the costs or expenses and the sales revenue occur in a future time, one has to account for the time value of money and the risks. This is done by calculating the Present Value of these cash flows. A discount rate is used to calculate the Present Value. The discount rate varies within organizations and industries. This takes into account the risk factors, economic fundamentals, the investment mix, and the debt structuring. The present value of the future returns less the investment in the beginning gives the Net Present Value (NPV). The $/Kwhr rate used to calculate sales revenue to achieve a zero NPV is the Levelized Cost of Energy.

Calculation of LCOETo calculate LCOE one would require The capacity of the plant expressed in megawatts or kilowatts. The capacity can remain the same throughout the lifetime or can be reduced due to operational wear and tear. The yearly plant load factor . This accounts for the availability and utilization of the plant, the maintenance outages, and load reductions due to demand or machine defects. This two will give the units of electricity generated during the life time of the plant. This together with unit cost of electricity will give the Sales revenue. The costs can be of five major types: Investment costs. This includes the yearly interest charges, the paybacks, and other financial charges. The initial investment or the overnight charges is considered as occurring at the end of the construction phase of the project and is used to calculate the Net Present Value. Taxes. Depending on regulations and policies. Also to be included are subsidies or incentives for renewable power. Fuel cost. To calculate this one would require the heat rate or efficiency of the plant (kilojoules per kilo watt hour) , the cost of fuel ($/kg or $/Kg) and escalations to the cost of the fuel. Operation and maintenance costs. This is taken as a fixed number for each unit of electricity generated. Depreciation and major replacement costs. To calculate the Net Present Value one will require the discount rate expressed as percentage. It could be in the range of 10 to 18 %, which is matter of national and organizational policies. Using an Excel spreadsheet will be the easiest way to do this calculation. The cost can be calculated for each year. The sales revenue for each year is calculated based on the units generated and an assumed value of unit electricity cost. The difference of the sales revenue and the costs give the yearly cash flow. The present value for this series of cash flow is calculated by the NPV function in Excel. The present value less the initial investment gives the Net Present Value. The assumed value of electricity cost is adjusted or iterated to get a zero NPV. The Goal seek function in an Excel spreadsheet also can be used for this. The unit electricity cost to achieve zero NPV is the Levelized Cost of Energy.

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Clean Coal Fired Power PlantsCoal has been in an imbroglio with environmentalists on one hand and the power generation industry on the other. In the midst are the proponents of Clean Coal. Can Coal be clean? Is it a myth or a reality? Our civilization is founded on coal, more completely than one realizes until one stops to think about it. The machines that keep us alive, and the machines that make machines, are all directly or indirectly dependent upon coal. - George Orwell in his essay Down The Mine. Our main energy source has been coal since the invention of the steam engine, through the Industrial Revolution and continues to be so today. With Global warming taking the center stage, the question asked is should coal be our main energy source? Consider these three facts about coal combustion. Coal gives us energy in the form of heat. Heat release takes place by the exothermic reaction of carbon in coal with oxygen in air to form carbon dioxide. Therefore, if coal is to give heat, then there will be carbon dioxide. 3.67 mols of CO2 will be formed for every mol of carbon burned - no more and no less. This reaction has made coal the biggest energy supplier.This has also made coal the biggest producer of CO2, the green house gas affecting Global Warming. This is the inevitable truth. Coal exists in nature not as pure carbon, but as a mineral rock containing predominantly carbon with ash and water. It also includes small amounts of hydrogen, sulphur, and other elements. Depending on the rank of coal and the location of the mines, the carbon percentages vary. When coal burns, it is only the carbon and the hydrogen that contributes to the heat energy. All other components convert to residue (ash) and gaseous emissions like sulphur dioxide, nitrogen oxides and carbon dioxide. These along with trace elements like mercury disperse into the atmosphere. This residue and emissions is what earned coal the tag dirty fuel. Coal lies deep below the earths surface. To mine or reach the coal layer the top layers of soil have to be moved. This destroys the vegetation, trees, and agriculture above. This also works against the clean coal image.

For a given coal, the elimination or reduction of the residual matter and emissions are not possible. These are chemically fixed. What can change is only the method of capture and its disposal. What the proponents of Clean Coal Technology are doing is only this. In earlier days, dispersion of the ash and gaseous emissions to the atmosphere was through the chimney. The after effects were disastrous, affecting a large population base. Acid rain, ground level ozone, respiratory diseases, and reduced visibility all were a result of this. Strict environmental regulations helped in developing technology to capture these emissions. Today electrostatic precipitators collect almost all of the ash particles. Flue gas Desulphurization Units and Selective Catalytic Reduction units capture most of the emissions. The captured ash and residues will turn out to be environmental issues as these coal fired power plants age. The collected ash or the sulphate from the desulphurization units over the years make massive piles that will lead to environmental issues. A 600 MW Coal fired power plant produces almost a million tons of ash in three years. It affects agriculture, groundwater, and the health of the people living nearby. It may take many years to notice the effects. This does not make the coal clean.

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NOx and COThe process of combustion itself generates some undesirable gaseous emissions like NOx and CO. These, though not necessarily a part of the basic reaction, are present in everyday combustion. Advances in combustion technology and operation philosophy have seen considerable reduction of these emissions. This is really eliminating an unwanted emission and a success of clean coal technology.

CO2 emissionsCO2 still emits into the atmosphere. Commercial scale capturing of CO 2 ( Carbon Sequestering Systems ) and sending it to underground reservoirs is yet to be viable. CO2 emission will continue to be the main burden of coal, unless large scale forestry takes place to absorb the emissions.

New Combustion ProcessAdvanced technologies like Integrated Coal Gasification, Circulating Fluidized Bed technology, and coal washeries improve the utilization and efficiency of coal combustion. This also makes it easy for capturing the emissions and residues. Even though these are termed clean coal technologies, they are in fact only making the coal combustion cleaner.

Residue UtilizationUtilizing the captured residue, substituting for other natural resources, is an environmentally better disposal method. Technologies like: Mixing fly ash in cement, Using fly ash for road laying Using fly ash to make bricks Using sulphate from flue gas desulphurization for making gypsum boards Even though this is only a smaller percentage of the residue or emissions captured, this is a constructive clean coal method. Nature has taken millions of years to sequester the carbon into coal. In a few milliseconds, man has found the means to release it back to the atmosphere. The Pandoras box has been opened, and we can only wait for Hope. A real clean coal with no emissions or environmental effects is impossible, but a cleaner coal is a must.

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Fly Ash Erosion in Boilers Firing High Ash CoalsCoal is one of the the main fuels for power production. Coal quality deterioration over the years has created challenges for boiler designers the world over to compact and minimize erosion in pressure parts. Fly ash erosion is a major factor for pressure parts damage in high ash coal fired boilers. In high ash coal fired boilers, fly ash erosion is a major concern and the tube failures due to fly ash erosion are almost 35% of the total tube failures. The amount of ash in coal and its velocity are major factors in the rate of

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pressure part erosion. Fly ash erosion is experienced in the economizer, primary SH, and inlet section of steam reheater tubes. When non-uniform flue gas flow distribution occurs in these areas, the rate of erosion increases multifold. Factors influencing fly ash erosion in coal fired boilers are The velocity of flue gas The temperature of flue gas The mineral content in coal The change in direction of flue gas The arrangement of pressure parts and The operation above the maximum conditions design rating or with excess airflow above design rate.

Of these factors, the velocity of flue gas, the temperature of flue gas (ash), and mineral matter in coal are the main influencing factors.

The velocity of flue gasFor low ash coals, the weight loss in pressure parts due to erosion is proportional to flue gas velocity to the power of 1.99. However for high ash Gondwana coals the erosion rate is velocity to the power of 3 to 5. The power depends upon the percentage of ash in coal, the percentage of silica in coal ash, the percentage of quartz in this silica, the percentage of alpha quartz in this quartz, and the structure of alpha quartz.

Temperature of flue gasHigher temperature softens the minerals in the ash as well as reduces the strength properties of the material of pressure parts; due to this ash erosion is not predominant in high temperature zones like furnaces, final superheaters, exit reheaters, etc. The ash erosion mainly starts in the conventional two-pass boilers from the area where gas temperature is around 700 750 deg.C. The low temperature superheater (LTSH) and economizer are the areas where ash erosion is severe in a conventional two-pass boiler. The temperature of flue gas entry to LTSH can be around 650 to 700 degree C and leaving, the economizer can be around 350 300 degree C. The minerals, which mainly constitute the ash in flue gas at these temperatures, become hard and attain its full abrasiveness.

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Predicting Combustibles in Pulverized Coal Fired Boilers - Fly Ash and Bottom AshPredicting the percentage of combustibles in fly ash in a tangential fired boiler using proximate analysis of coal gives boiler designers an edge during the proposal and contract stages. Here is how to predict fly ash and bottom ash combustibles in order to compute carbon loss in a boiler. In boilers with pulverized firing systems, about 80% of the ash in coal being fired is carried as fly ash. The other about 20% get collected as bottom ash. During the combustion of coal, some portion of the hydrocarbon, mainly char, leaves the furnace as unburned particles. The amount of such unburned particles leaving the furnace depends on many factors like the coal property, the type of burning system, the resident time available in the furnace, the ash percentage in coal, the calorific value of coal, the fuel ratio, the operating conditions, etc. The existence of unburned carbon in ash decreases not only the combustion efficiency, but also the grade of fly ash for commercial sale.

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Carbon loss is influenced by the following: (1) coal preparation and grinding, such as changes in ash and maceral content ; mean, standard deviation, and higher moments of the particle size distribution; moisture remaining in the pulverized coal, (2) properties of the pulverized coal and its char like heating value, char yield on pyrolysis, char structure, char reactivity, ash content and composition, and characteristics, and (3) adjustments of the burners and furnace such as air preheat, excess air, mixing, residence time, and furnace temperature. Hottel and Stewert (1940) were the first to consider the interaction between furnace design and coal properties in the determination of carbon conversion, analyzing the effects of grind, reactivity, temperature, excess air, and residence time on unburned carbon loss. With the estimated values of percentage combustibles in fly ash as well as bottom ash, the carbon loss can be calculated by using the formula given in BS_EN_12952, ASTM, PTC 4 and any other International Standards. Boiler designers during the design stage have only proximate analysis, ultimate analysis and ash composition of coal. Carbon loss calculation involves calculating the carbon loss in fly ash and bottom ash. This article provides a tool for the designers and others to predict the percentage of combustibles in fly ash and bottom ash in a tangential fired boiler using proximate analysis of coal and the residence time in the boiler furnace. Based on combustibles in flyash and bottom ash, it is possible to compute the carbon loss in a boiler.

Fly ash unburned predictionThe major portion of carbon loss in a boiler is from unburned carbon in fly ash. A method was developed by me after a large volume of data was subjected to analysis and validation. It is seen from the analysis and literatures that the fuel ratio i.e. the ratio of fixed carbon and volatile matter in coal has a very significant effect. The ash in coal is a burden for combustion and can cause large problems during and after combustion. Deposits and slagging in boiler furnaces using high amounts of medium slagging and slagging coals are common. After combustion they can foul the heat transfer surface in the convection region. So it is seen that log of ash % correlates well with fly ash combustibles. Coal calorific value indicates the heat value of the coal being fired hence has to be taken into account when we want to predict the fly ash combustibles. The calorific value of the coal in question divided by the calorific value of carbon gives meaning to the factor. This indicates the relative stage where the coal in question lies with respect to its ultimate transformation and also is an indirect indicator of the difficulty to ignite and burn. I would not like to call it as reactivity as the same has not been studied / understood much with respect to this ratio of coal. Inverse of residence time is another major factor which affects the fly ash combustibles. As boilers are operated within a close range of excess air and fineness of coal, these variables do not affect the unburned to any significant level. A factor combining all the parameters is evolved which is used for fitting a curve with percentage combustibles in fly ash. The factor is defined as

[{(FC/VM)+(HVV/8080)*100+Log(A)}/Res^2] The equation governing the curve fitted on a fourth order polynomial is Y = -3E-06 X4 + 0.0004 X3 - 0.0161 X2 + 0.2969 X - 0.9438 with a R square value of 0.8824.As this predictive equation is only made for a pulverized coal tangentially fired boiler, this has to be verified for pulverized coal wall firing, down shot firing, opposed firing, etc. However, more than 50% of the pulverized coal fired boilers in the world are equipped with tangential firing system.

Bottom ash unburned prediction

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The single most independent variable affecting the bottom ash combustibles is the plus 50 mesh size of pulverized coal. A plot of percentage bottom ash combustible plotted against percentage plus 50 particle sizes has a fourth order polynomial curve with an R2 value of 0.9412. The equation governing this fit is

Y1 = 0.0233X14 - 0.3925X13 + 1.9277X12 - 0.1593X1 + 0.2357where, Y1 is percentage combustibles in bottom ash and X1 is plus 50 mesh particle percentage in the pulverized coal. It is seen that this percentage plus 50 in the pulverized fuel should be retained below 2% to minimize the percentage combustible in bottom ash. This is generally recommended by boiler manufacturers.

Flyash & Bottom ash Combustible

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Remaining Life Estimation in Boiler Pressure PartsRemaining life estimation in boiler pressure parts is a very important tool towards predictive maintenance of boiler pressure parts. Boilers are made up of large amount of tubing and pipes of different materials which will have to withstand high pressure and temperature. Boilers are made up of a large amount of tubing and pipes of different materials which will have to withstand high pressure and temperature. These pressure parts undergo aging due to various reasons including internal and external deposition. Above a particular limit of aging these pressure parts start failing frequently, which leads to higher outage of the units. To understand the health condition of these pressure parts there are many scientific methods used today which can estimate the remaining life of the pressure parts.

Reason to estimate remaining lifeThe high temperatures to which the pressure parts are subjected at elevated pressure lead to creep stress. The starting and stopping of the unit results in fatigue stress, and the fuels burnt can cause corrosion in various areas in the boiler. The water used for steam generation leaves deposits inside the tube which increases the metal temperature leading to long term overheating. Residual stresses during manufacturing, the vibrations due to flow over the tube, mechanical vibrations, erosion due to the abrasive nature of the fuel, etc, do occur in a boiler. Operation of the boiler at elevated temperature and parameters leads to stresses higher than the design levels. All of these, individually or combined, lead to material degradations of different magnitude resulting in failure. To avoid any such forced outage, boiler owners would like to have a preventive method. Remaining life estimation of pressure parts helps this requirement by a scientific method of analysis.

Steps involved in remaining life estimationThe first and foremost requirement of remaining life estimation is to study the past data of the plant. The predicted performance data, The guarantee performance test data, The operating data for the period of time of operation of unit, Operating practice adopted The maintenance data, Failures and repairs Previous inspection reports The outage data, Areas of frequent failure if any, Inadequacy of any nature in boiler, Modifications carried out for achieving the performance, Other major modifications, The procedure adopted for welding during the years, Any special welding method used, Variation in water chemistry Any post operational acid cleaning done The number of startups and shutdowns of the unit Temperature excursions in various areas Any special study carried out and the reason for the study The owners requirement after the life extension program

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After consolidation of the data and understanding the data, the next step is to do a set of field tests. These field tests include. Visual inspection for o Erosion, corrosion o Swelling, scaling o Deposits, misalignments o Supports, pipe hangers etc Dimensional checks o Thickness o Outside diameter Non-destructive examination Penetrant testing including fluorescent type Magnetic particle inspection (Wet fluorescent & Dry) Ultrasonic tests In-situ hardness checks Eddy current testing Tube sampling water walls for internal deposit analysis Superheater and reheater sample if needed Special examinations for o WW H2 embrittlement o Superheater/Reheater for oxide scales, o Metallographic examination of thick wall component o Fibroscopic inspection of headers and other regions needed o Spot chemical check when needed

Once when the field tests are completed, a few laboratory examinations and tests are carried out. The tube samples taken from the water walls, superheater, and reheater are subjected to microscopic examination (Light Microscopy & Scanning Electron Mic