Boiler Operation and Control

1. Operation in a glimpse: A boiler operates using the feed water system, the steam system, the fuel system and the draft system.  The feed water system supplies water to the boiler.  The steam system controls and directs the steam produced in the boiler.  The fuel system supplies fuel and controls combustion to produce heat.  The draft system regulates the movement of air for combustion and evacuates gases of combustion. Water, steam fittings and accessories are required to supply and control water and steam in the boiler. Boiler fittings or trim are components such as valves directly attached to the boiler. Accessories are pieces of equipment not necessarily attached to the boiler, but required for the operation of the boiler.

2. A short description of the common boiler devices in operation: 1. Safety Valves are the most important fittings on the boiler. They should open to release pressure when pressure inside the boiler exceeds the maximum allowable working pressure or MAWP. Safety valves are installed at the highest part of the steam side of the boiler. No other valve shall be installed between the boiler and the safety valve. Safety valve capacity is measured in the amount of the steam that can be discharged per hour. The safety valve will remain open until sufficient steam is released and there is a specific amount of drop in Boiler Operation And Control

Safety Valve

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pressure. This drop in pressure is the blow down of the safety valve. Safety valve capacity and blow down is listed on the data plate on the safety valve. Spring loaded safety valves are the most common safety valves. A spring exerts pressure on the valve against the valve seat to keep the valve closed. When pressure inside the boiler exceeds the set popping pressure, the pressure forces the valve open to release. The number of safety valves required and the frequency and procedures for testing safety valves is also specified by the ASME Code. Adjustment or repairs to safety valves must be performed by the manufacturer or an assembler authorized by the manufacturer. 2. Water fittings and accessories control the amount, pressure and temperature of water supplied to and from the boiler. Water in the boiler must be maintained at the normal operating water level or NOWL. Low water conditions can damage the boiler and could cause a boiler explosion. High water conditions can cause carryover. Carryover occurs when small water droplets are carried in steam lines. Carryover can result in water hammer. Water hammer is a banging condition caused by hydraulic pressure that can damage equipment.

3. Feed water Valves control the flow of feed water from the feed water pump to the boiler. Feed water stop valves are globe valves located on the feed water line. They isolate the boiler from feed water accessories. The feed water stop valve is positioned closest to the boiler to stop the flow of water out of the boiler for maintenance, or if the check valve malfunctions. The feed water check valve is located next to the feed water stop valve and prevents feed water from flowing from the boiler back to the feed water pump. The feed water check valve opens and closes automatically with a swinging disc. When water is fed to the boiler it opens. If water flows back from the boiler the valve closes.

4. Water Column minimizes the water turbulence in the gage glass to provide accurate water level reading.

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Water columns are located at the NOWL, with the lowest part of the water column positioned at least 3" above the heating system. Water columns for high pressure boilers consist of the main column and three tricocks. High and low water alarms or whistles may be attached to the top and bottom tricocks. 5. The Gage Glass is used to visually monitor the water level in the boiler. Isolation valves located at the top and bottom permit the changing of gage glasses.

Gage Glass

6. A Blow down Valve at the bottom of the gage glass is used to remove sludge and sediment. Tubular gage glasses are used for pressure up to 400 psig. All boilers must have two methods of determining the boiler water level. The gage glass serves as the primary method of determining boiler water level. If the water cannot be seen in the gage glass, the tricocks are used as a secondary method of determining boiler water level. The middle tricock is located at the NOWL. If water comes out of the middle tricock, the gage glass is not functioning properly. If water comes out of the top tricock, there is a high water condition in the boiler. If water comes out of the bottom tricock, water may be safely added to the boiler. If steam comes out of the bottom tricock, water must not be added to the boiler. Secure the fuel immediately. Adding water could cause a boiler explosion. 7. Makeup Water replaces boiler water lost from leaks or from the lack of condensate returned in the boiler. Makeup water is fed manually or automatically. Boilers can have both manual and automatic systems. If the boiler has both, the manual always bypasses the automatic system. Boiler operators must know how to supply makeup water quickly to the boiler in the event of a low water condition. Manual systems feed city water with a hand operated valve. Automatic systems feed city water with a float control valve Boiler Operation And Control

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mounted slightly below the NOWL. If the float drops from a low water level, the valve in the city water line is open. As the water level rises, the float rises to close the valve.

8. The Low Water Fuel Cut Off shuts off fuel to the burner in the event of a low water condition in the boiler. The low water fuel cut off is located 2" to 6" below the NOWL. Low water fuel cut offs are available with or without an integral water column. Low water fuel cut offs must be tested monthly or more often depending on plant procedures and requirements. Low water fuel cut offs operate using an electric probe or a float sensor. The float senses a drop in water level. Switches in the low water fuel cut off are wired to the burner control to shut off fuel to the burner when the water level drops in the chamber. 9. The Feed water Regulator maintains the NOWL in the boiler by controlling the amount of condensate return pumped to the boiler from the condensate return tank. The correct water level is maintained with a feed water regulator, but boiler water level must still be checked periodically by the boiler operator. Feed Water Regulator

10. Feed water Pumps are used with feed water regulators to pump feed water to the boiler. Pressure must be sufficient to overcome boiler water pressure to maintain the NOWL in the boiler. For maximum safety, plants having one steam driven feed water pump must have a back up feed water pump driven by electricity. Feed water pumps may be reciprocating, centrifugal or turbine.

Boiler Operation And Control

Feed water Pump

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11. Reciprocating feed water pumps are steam driven and use a piston to discharge

water to the feed water line. They are limited in capacity and are used on small boilers. 12. Centrifugal feed water pumps are electric motor or steam driven. They are the most common feed water pump. Centrifugal force moves water to the outside edge of the rotating impeller. The casing directs water from the impeller to the discharge piping. Discharge pressure is dependent on impeller speed. 13. Turbine feed water pumps are steam driven and operate similarly to centrifugal feed water pumps. 14. Feed water Heaters heat water before it enters the boiler drum to remove oxygen and other gases which may cause corrosion. Feed water heaters are either open or closed. Open feed water heaters allow steam and water to mix as they enter an enclosed steel chamber. They are located above the feed water pump to produce a positive pressure on the suction side of the pump. Closed feed water heaters have a large number of tubes inside an enclosed steel vessel. Steam and water do not come in contact, but feed water goes through the tubes and steam is allowed in the vessel to preheat the feed water. They are located on the discharge side of the feed water pump.

15. Bottom Blow down Valves release water from the boiler to reduce water level, remove sludge and sediment, reduce chemical concentrations or drain the boiler. Two valves are commonly used, a quick opening and screw valve. During blow down the quick opening valve is opened first, the screw valve is opened next and takes the wear and tear from blow down. Water is discharged to the blow down tank. A blow down tank collects water to protect the sewer from the hot boiler water. After blow down, the screw valve is closed first and the quick opening valve is closed last. 16. Steam Fittings & Accessories remove air, control steam flow, and maintain the required steam pressure in the boiler. Steam fittings are also used to direct steam to various locations for heating and process. Boiler Operation And Control

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17. Steam Pressure Gauges and vacuum gages monitor pressure inside the boiler. The range of these gages should be 1-1/2 to 2 times the MAWP of the boiler. For example: on a low pressure boiler, a maximum steam pressure on the pressure gage reads 30 psig as the MAWP is 15 psig.

Pressure Gauge

18. Steam Valves commonly used include a gate valve used for the main steam stop valve and the globe valve. The main steam stop valve cuts the boiler in online allowing steam to flow from the boiler or takes it off line. This is an outside stem and yoke or OS&Y valve. The position of the stem indicates whether the valve is open or closed. The valve is opened with the stem out and closed with the stem in. This provides quick information to the boiler operator. 19. The globe valve controls the flow of steam passing under the valve seat through the valve. This change in direction causes a decrease in steam pressure. A globe valve decreases steam flow and can be used to vary the amount of steam flow. This should never be used as a main steam stop valve.

Globe Valve

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20. Steam Traps remove condensate from steam in lines from the boiler. Steam traps work automatically and increase boiler plant efficiency. They also prevent water hammer by expelling air and condensate from the steam lines without loss of steam. Steam traps are located after the main steam header throughout the system. Steam traps commonly used include the inverted bucket, the thermostatic and the float thermostatic. In Steam Trap the inverted bucket steam trap steam enters the bottom flowing into the inverted bucket. The steam holds the bucket up. As condensate fills the steam trap the bucket loses buoyancy and sinks to open the discharge valve. The thermostatic steam trap has a bellows filled with a fluid that boils at steam temperature. As the fluid boils vapors expand the bellows to push the valve closed. When the temperature drops below steam temperature, the bellows contract to open the valve and discharge condensate. A variation of the thermostatic steam trap is the float thermostatic steam trap. A float opens and closes depending on the amount of condensate in the trap bowl. Condensate is drawn out by return vacuum. 21. Steam Strainers remove scale or dirt from the steam and are located in the piping prior to steam trap inlet. Scale or dirt can clog discharge orifices in the steam trap. Steam strainers must be cleaned regularly. Steam Strainer

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3. SUMMARY OF DEVICES USED  The safety valve is the most important fitting on the boiler.  The gage glass is used to visually monitor the water level in the boiler.  Tricocks are used as a secondary device for determining water level in the boiler.  Makeup water replaces water lost from leaks or lack of condensate return to the boiler.  The low water fuel cut off shuts off fuel to the burner in the event of a low water condition.  Steam pressure gages and vacuum gages are used to indicate the pressure inside the boiler.

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4. Process of raising steam from cold in a Scotch boiler:  If the boiler has been opened up for cleaning or repairs check that all work has been completed, and carried out in a satisfactory manner. Ensure that all tools, etc. have been removed. Examine all internal pipes and fittings to see that they are in place, and properly fitted. Check that the blow down valve is clear. Then carry out the following procedure: 1. Fit lower manhole door. 2. Check external boiler fittings to see they are in order. 3. See that all blanks are removed from safety valves, blow down line, etc. 4. Fill boiler with water to about one-quarter of the water level gauge glass. If possible hot water heated by means of a feed heater should be used. The initial dose of feed treatment chemicals, mixed with water, can be poured in at the top manhole door at this stage if required .Then fit top manhole door. 5. Make sure air vent is open. 6. Set one fire away at lowest possible rate. 7. Use the smallest burner tip available. 8. By-pass air heater if fitted. 9. Change furnaces over every twenty minutes. 10. After about one hour start to circulate the boiler by means of auxiliary feed pump and blow down valve connection, or by patent circular if fitted. If no means of circulation is provided, continue firing at lowest rate until the boiler is well warmed through especially below the furnaces. Running or blowing out a small amount of water at this stage will assist in promoting natural circulation if no other means is available . Continue circulating for about four hours, raising the temperature of the boiler at a rate of about 6°C per hour. Water drawn off at the salinometer cock can be used to check water temperature below 100°C. At the end of this time set fires away in all furnaces, still at the lowest rate. 11. Close the air vent. Nuts on manhole doors and any new joints should be nipped up. 12. Circulating the boiler can now be stopped, and steam pressure slowly raised during the next 7-8 hours to within about 100 kN/m' of the working pressure. 13. Test the water gauge.

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 The boiler is now ready to be put into service. About 12 hours should be allowed for the complete operation provided some means of circulating the boiler is provided. If circulation cannot be carried out, the steam raising procedure must be carried out more slowly, taking about 18-24 hours for the complete operation. This is due to the fact that water is a very poor conductor of heat, and heat from the furnace will be carried up by convection currents leaving the water below the furnace cold. This will lead to severe stresses being set up in the lower sections of the circumferential joints of the boiler shell if steam raising is carried out too rapidly, and can lead to leakage and 'grooving' of the end plate flanging . If steam is being raised simultaneously on more than one boiler, use the feed pump to circulate each boiler in turn, for about ten minutes each.

5. General Precautions to be noticed on a working boiler There are various items to be inspected on a running boiler such as all the individual equipment operating control signals, flow rates, temperatures and general load conditions. They must be checked regularly so as to become aware quickly of any deviations from the norm. Rarely do emergency conditions arise without some previous indication, which an alert should be recognized, investigated, and then taken corrective action before the situation gets out of hand.

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6. General precautions for optimum running and safety regulations Ensure that all boiler and associated safety shut-down devices are maintained in full operational condition, and tested at regular intervals so as to be ready for instant operation. 1. All alarm and automatic control systems must be kept within the manufacturer's recommended operating limits. Do not allow equipment to be taken out of operation for reasons which could reasonably be rectified. 2. All control room check lists must be kept up to date, with any known deviations from normal operating procedures noted for immediate reference. Any deviations that are un-noticed may build up to potentially serious conditions. 3. Automatic control loops do not think for themselves, and subjected to external irregularities will still try to perform as normal. This can result in their final control action being incorrect, or to some other piece of equipment being overworked in an attempt to compensate. 4. In situations where the automatic control of critical parameters is not dependable, or where it becomes necessary to use manual control, reduce operating conditions so as to increase acceptable margins of error. 5. High performance water tube boilers demand high quality feed water, so do not tolerate any deterioration of feed water conditions; immediately trace the source of any contamination, and rectify the fault. 6. Do not neglect leakage of high pressure, high temperature steam, as even minor leaks will rapidly deteriorate.

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7. No attempt should be made to approach the site of leakage directly, but the defective system should be shut down as soon as is practicable and the leakage rectified. 8. Do not allow steam and water leaks to go un-corrected as, apart from reduction in plant efficiency, they also lead to increased demand for extra feed with an inevitable increase in boiler water impurities. 9. Always be alert for conditions which increase the potential fire risk within the engine room: the best method of fire fighting is not to allow one to start. Thus all spaces, tank tops etc. must be kept clean, dry, and well lit. This not only improves the work environment, but also makes for the early detection of any leakage and encourages early repair. 10. Store any necessary stocks of combustibles remote from sources of ignition. Maintain all oil systems tight and free from leaks and overspills. Follow correct flashing-up procedures for the boiler at all times, especially in the case of roof-fired radiant heat boilers. Be familiar with the fire fighting systems and equipment, and ensure that all under your direct control are kept at a full state of readiness at all times. 11. Assess particular risk areas, especially in engine room sp aces, and formulate your approach in case of emergency; decide in some detail how you would deal with fires at various sites in the engine room. Make sure that your are familiar with the quick closing fuel shut-off valves, the remotely operated steam shut-off valves etc. to enable the boiler to be put in a safe condition if having to abandon the machinery spaces in the event of a fire.

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7. The basic procedure for cleaning a boiler after a period of service. The frequency of boiler cleaning depends upon various factors such as the nature of the service in which the vessel has been engaged, the quality of feed water and fuel with which the boiler has been supplied. 1. Where possible the boiler should be shut down at least 24 hours prior to cleaning, with if practicable the soot blowers being operated just before shut-down. When boiler pressure has fallen to about 400 kN/m2, open blow down valves on drums and headers to remove sludge deposits. Finally empty the boiler by running down through suitable drains etc. Do not attempt to cool the boiler forcibly as this can lead to thermal shock. All fuel, feed and steam lines must be isolated, and the appropriate valves locked or lashed shut. Air vents must be left open to prevent a vacuum forming in the boiler as it cools down. 2. Should cleaning prove to be necessary, remove any internal fittings required to provide access to tubes etc., keeping a record of any items removed. Also note that all attachment bolts are present and that a\l are accounted for when refitting. 3. Where the boiler design permits, cleaning can 'be carried out by mechanical brushes with flexible drives; if these are not suitable, chemical cleaning must be used. After cleaning, flush the boiler through with distilled water. 4. Upon completion of cleaning, tubes etc. must be proved clear. Where access is available, search balls or flexible search wires can be used. Where neither is practical, high pressure water or air jets can be used, the rates of discharge from the outlet end being used to indicate whether any obstruction is present within the tube. Where necessary, welded nipples are removed to permit sighting through headers. With welded boilers the tubes must be carefully searched before welding takes place and suitable precautions then taken to avoid the entry of any foreign matter into tubes etc.

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5. Where work is to be carried out in the drum, rubber or plastic mats can be used, with flexible wires attached and secured outside the drum so that they are not left inside when the boiler is closed up. 6. Check all orifices to boiler mountings to prove that they are clear, and ensure that all tools, cleaning materials etc. have been removed from the boiler. All internal fittings removed must be replaced. Fit new gaskets to all doors and headers, and close up the boiler. 7. All personnel working in the boiler must be impressed with the importance of the avoidance of any objects entering the tubes after the boiler has been searched, but that if a mishap should occur it must be reported before the boiler is finally closed up. 8. External Cleaning Spaces between tubes can become choked with deposits which are not removed by soot blowing. Where sufficiently loose they may be removed by dry cleaning using brushes or compressed air. But in most cases water washing will be necessary. Washing will require hot water, preferably fresh, under pressure and delivered by suitable lances. The water serves two purposes, dissolving the soluble deposits and then breaking up and flushing away the loosened insoluble residue. 9. Once started. Washing should be continuous and thorough, as any half-dissolved deposits remaining tend to harden off, baking on hard when the boiler is again fired, then to prove extremely difficult to remove during any subsequent cleaning operations. 10. Prior to cleaning, bitumastic paint should be applied around tubes where they enter refractory material, in order to prevent water soaking in to cause external corrosion

11. . Efficient drainage must be provided, with sometimes drains below the furnace floor requiring the removal of some furnace refractory. Where only a particular section is to be washed, hoppers can be rigged beneath the work area, and the water drained off through a convenient access door.

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12. For stubborn deposits a wetting agent may be sprayed on prior to washing. 13. After washing. Check that no damp deposits remain around tube ends, in crevices etc. removing any remaining traces found. In a similar manner remove any deposits in double casings around economizer headers etc., especially if they have become damp due to water entering during the washing process. 14. Ensure that all cleaning materials, tools. Staging etc. have been removed, and any refractory removed has been replaced, after which the access doors can be replaced. 15. Run the fans at full power with air registers full open for some minutes to clear any loose deposits. Then dry the boiler out by flashing up in the normal manner. If this can’t be done immediately, then hot air from steam air heaters or from portable units must be blown through to dry the external surfaces.

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8. Boiler operation from cold start 8.1. 1. 2. 3. 4. 5. 6. 7. 8. 9.

Make sure all maintenance services are finished Make sure all air gates and flue gases gates are closed Make sure no personal are working on site Make sure all electric devices have power Air compressors must be working All air pressures in the system must be at normal Cooling water system must be ready Secondary Steam system must be on Drum must be filled with water

8.2. 1. 2. 3. 4. 5. 6. 7.

Preoperational precautions

Turning Feed Pump on:

Water tank level at normal (0) level Lubricating oil pressure < 1.4 bar Gear box at neutral position Valve for controlling lowest rate of feed water must be open Suction valve must be open Delivery Valve and bypass must be closed. Cooling water valve must be open

Steps

1. The bypass valve for the delivery pipe is opened 2. The delivery valve is opened 3. The control valve is opened for starting operation 4. The entrance valve to the economizer is opened The operating range for rate of feed water should be about (200-250 ton/hr) 5. After the drum is filled with water the delivery valve to the drum is closed to start operation 6. The ammonia (NH3) pump is turned on to increase the water PH 7. Hydrazine (N2H4) is used to remove Oxygen(O2) and increase PH 8. Sodium Phosphate (NA3PO4) is used to remove dissolved salts Boiler Operation And Control

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8.3.

Turning the air system and flue gas system on:

Precautions before operating

a) b) c) d)

Air pressure must be 8 bar Cooling water system must be normal point Inlet and outlet gates for the air must be closed Inlet and outlet gates for the flue gases must be closed

Air preheaters are to be turned on now

a) b) c) d)

Open the inlet and outlet gates for the flue gases Open the inlet and outlet gates for the air The forced air fan is to be turned on now After 15 sec the induced fan is to be turned on.

8.4.

Turning the Fans on:

Precautions for turning fans on:

1. 2. 3. 4. 5. 6.

Air Preheater must be turned on Cooling water system must be operational Air suction gates must be closed on both sides Air delivery gates must be closed on both sides Lubricating oil pump must be operational Hydraulic coupling must be at normal (0) level

Turning air Fans on procedure:

1. Turn the fan on 2. Hydraulic coupling is to be opened 20 % 3. The delivery gate for the fan is to be opened 4. The suction gate for the fan is to be opened The hydraulic coupling and the fan air suction gates must be set to AUTO setting All gates must be put to AUTO setting as follows: Over fire Damper 20 % open Aux. Dampers 40 % open Fuel Air Damper 60%

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Turning the flue gas fan and flame detector on:

1. Air fans must be turned on 2. Outlet gates for air must be open 3. Circulating Flue gases fans are to be turned on now

8.5. 1. 2. 3. 4. 5.

Operating Precautions:

Air fans must be on Cooling water system must be operational Inlet and outlet flue gases gates must be closed Heater gates must be opened Lubricating oil pump must be on

Secondary steam system must be turned on Secondary steam must be at 360 C at about 13.5 bar Secondary steam destinations:

1. 2. 3. 4. 5.

Air heaters Gas absorbers Air dumpers steam atomizer burners Secondary steam for steam turbines

8.6.

Fuel System:

1. Fuel level must be normal 2. Leakage preventing pump must be operational 3. suction valve must be opened 4. control valve for the lowest level of fuel must be opened 5. the delivery valve must be opened The main fuel pump can now be turned on Minimum pressure for the fuel is 20 bar by adjusting the control valve The steam atomizing system is now to be turned on

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After checking that the steam level is normal the inlet valve for the secondary steam is to be opened The atomizing steam pressure is to be 11 bar

8.7.

Purging condition

1. Air flow not much than 30% 2. One or more FDF running 3. Fuel Oil trip valve closed 4. Fuel gas trip valve closed 5. All igniter off 6. All scanner no flame. 7. MFT 8. Igniter gas oil supply pressure must be proper 9. Fuel oil or gas supply pressure must be proper 10. All flue gases and air damper are to be opened 11. All burners valve must be closed 12. BCS power supply normal 13. All Aux. Damper modulating

8.8.

Boiler Storage

As soon as possible after the end of the heating season, take these steps, where applicable: 1. 2. 3. 4. 5. 6.

Remove all fuses from the burner circuit. Remove soot and ash from the furnace, tubes, and flue surfaces. Remove all fly ash from stack cleanout. Drain the broiler completely after letting the water cool. Flush the boiler to remove all sludge, and loose scale particles. See that defective tubes, nipples, stay bolts, packings, and insulation are repaired or replaced as required. 7. Clean and overhaul all boiler accessories such as safety valves, gauge glasses, and firing equipment. Special attention should be given to low-water cutoffs and feedwater regulators to ascertain that float (or electrode) chambers and connections are free of deposits. 8. Check the condensate return system for tightness of components. Boiler Operation And Control

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9. My Boiler won't start - what to do first! If you notice a change in boiler performance such as new noises, smells, rising stack temperatures or continually resetting safety devices. Although unexpected mechanical failures do occur boiler's safety or operational devices is preventing your boiler from starting. Most safety devices have manual reset buttons that need to be reset before boiler operation can continue. Continual resetting of safety devices is an indication of unsafe operating conditions. Prompt attention by your boiler technician is required.  Locate all devices that can prevent your boiler from starting.

9.1.

Burner controller:

The controller is usually located in front of the burner. On a call for heat the controller starts a sequence of events that ensure safe operation before the burner is allowed to start. The controller continues to monitor burner operation while the boiler is running. If for any reason the controller senses an unsafe operating condition it will shut the burner off. Pushing the manual reset on the controller will often restart the boiler.

9.2.

High pressure or temperature switch:

This device is a safety backup to the "operator" control. It has a manual reset which when pressed to start the boiler indicates that the "operator" control has failed.

9.3.

Gas pressure switches on the fuel train:

The natural gas fuel train usually has two pressure switches. The low pressure switch locks out the boiler when too little gas is available for operation. The high pressure switch locks out the boiler when the regulator is allowing too high a gas pressure. Both switches have a manual reset.

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9.4.

Low water cutoff:

The low water cutoff may have a manual reset. When reset indicates a low water condition existed in the boiler.

9.5. Other devices that may prevent the boiler from starting:

9.5.1.

Time clocks:

Time clocks or other energy management devices may restrict boiler operation during weekends, evenings or other times of the day. Check their operating schedule.

9.5.2.

Outdoor temperature limits:

These devices sense outdoor temperatures and prevent boiler operation above certain outdoor temperatures, usually 65 degrees.

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10. DANGEROUS CONDITIONS 10.1. Low Water A major reason for damages incurred to low pressure steam boilers is the low water within the boiler. If the condition of low water exists it can seriously weaken the structural members of the boiler, and result in needless inconvenience and cost. Low pressure boilers can be protected by installing an automatic water level control device. Steam boilers are usually equipped with automatic water level control devices. It must be noted, however, that most failures occur due to low water on boilers equipped with automatic control devices. The water control device will activate water supply or feed water pumps to introduce water at the proper level, interrupt the gas chain and ignition process when the water reaches the lowest permissible level, or perform both functions depending on design and interlocking systems. No matter how automatic a water control device may be, it is unable to operate properly if sediment scale and sludge are allowed to accumulate in the float chamber. Accumulations of matter will obstruct and interfere with the proper operation of the float device, if not properly maintained. To ensure for the reliability of the device, procedures must be established in your daily preventive maintenance program to allow "blow-down" the float chamber at Ieast once a day. Simply open the drain for 3 to 5 seconds making certain that the water drain piping is properly connected to a discharge line in accordance with City Building Codes. This brief drainage process will remove loose sediment deposits, and at the same time, test the operation of the water level control device. If the water level control device does not function properly it must be inspected, repaired and retested to guarantee proper operation.

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10.2. Overpressure Safe operation of a boiler is dependent on a vital accessory, the safety valve. Failure to test the safety valve on a regular basis or to open it manually periodically can result in heavy accumulations of scale, deposits of sediment or sludge near the valve. These conditions can cause the safety valve spring to solidify or the disc to seal, ultimately rendering the safety valve inoperative. A constantly simmering safety valve is a danger sign and must not be neglected. Your preventive maintenance program includes the documentation and inspection of the safety valve. A daily test must be performed when the boiler is in operation Simply raise the hand operating lever quickly to its limit and allow it to snap closed. Any tendency of a sticking, binding or leaking of the safety valve must be corrected immediately.

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Section 2 Boiler control 1-Boiler control overview The determinant that controls all the boiler's operations is called the 'master demand'. In thermal power-plant the steam is generated by burning fuel, and the master demand sets the burners firing at a rate that matches the steam production. This in turn requires the forced draught fans to deliver adequate air for the combustion of the fuel. The air input requires the products of combustion to be expelled from the combustion chamber by the induced draught fans, whose flow rate must be related to the steam flow. At the same time, water must be fed into the boiler to match the production of steam. As stated previously, a boiler is a complex, multivariable, interactive process. Each of the above parameters affects and is affected by all of the others. Funny example for load change These days, the demand for electricity in a developed nation is also affected quite dramatically by television broadcasts. During a major sporting event such as an international football match, sudden upsurges in demand will occur at half-time and full time, when viewers switch on their kettles. In the UK this can impose a sudden rise in demand of as much as 2 GW, which is the equivalent to the total output of a reasonably large power station. The master demand in a power-station application The response of a boiler/turbine unit in a power station is determined by the dynamic characteristics of the two major items of plant. These differ quite significantly from each other. The turbine, in very general terms, is capable of responding more quickly than the boiler to changes in demand. The response of the boiler is determined by the thermal inertia of its steam and water circuits and by the characteristics of the fuel system. For example, a coal-burning

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boiler, with its complex fuel-handling plant, will be much slower to respond to changes in demand than a gas-fired one. Also, the turndown of the plant (the range of steam flows over which it will be capable of operating under automatic control) will depend on the type of fuel being burned, with gas-fired units being inherently capable of operating over a wider dynamic range than their coal-fired equivalents. The design of the master system is determined by the role which the plant is expected to play, and here three options are available. The demand signal can be fed primarily to the turbine (boiler-following control); or to the boiler (turbine-following control); or it can be directed to both (co-ordinated unit control). Each of these results in a different performance of the unit, in a manner that will now be analyzed.

1-1-Boiler-following operation

With boiler-following control, the power-demand signal modulates the turbine throttle-valves to meet the load, while the boiler systems are modulated to keep the steam pressure constant.

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How can we achieve this? When valve closes, a drop in pressure happens, to regain the pressure to its predetermined value, we should decrease flow rate to decrease pressure drop across the valve, also when we decrease flow rate, pump head increases according to performance of the centrifugal pump. In such a system, the plant operates with the turbine throttle-valves partly closed. The action of opening or closing these valves provides the desired response to demand changes. Sudden load increases are met by opening the valves to release some of the stored energy within the boiler. When the demand falls, closing the valves increases the stored energy in the boiler. In such a system the turbine is the first to respond to the changes. The boiler control system reacts after these changes have been made, increasing or reducing the firing to restore the steam pressure to the set value.

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1-2-Turbine-following operation In the turbine-following system, the demand is fed directly to the boiler and the turbine throttle-valves are left to maintain a constant steam pressure. Particularly in the case of coal-fired plant, this method of operation offers slower response, because the turbine output is adjusted only after the boiler has reacted to the changed demand and as we know , the boiler response is much lower than turbine response especially the coal type. However, the turbine-following system enables the unit to be operated in a more efficient manner and tuning for optimum performance is easier than with the boilerfollowing system. We use this for large base-load power plant (where the unit runs at a fixed load, usually a high one, for most of the time), or with gas-fired plant where the response is comparatively rapid (as if we make the system boiler following, the boiler may fail to follow the fast response turbine).

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1-3-Co-ordinated unit control However, its design demands considerable knowledge of the characteristics and limitations of the major plant items. Also, commissioning of this type of system demands great skill and care if the full extent of the benefits is to be obtained. In particular, the rate-of change of the demand signals, as well as the extent of their dynamic range, will need to be constrained to prevent undesirable effects such as the stressing of pipework because of excessively steep rates-of-change of temperature.

Performance restriction for the control system is very dependent on the rate of heating the turbine and boiler. Control parameters should always be adjusted as all system component ages and their performance changes.

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1-4-Brief comparison between plant control modes As stated above, the co-ordinated unit load controller, when properly designed, commissioned and maintained, will provide the best possible response of the unit within the constraints of the plant itself. But for practical reasons it is not universally used.

1-4-1-Response of the boiler-following system Consider what happens when a sudden rise in demand occurs. The first response is for the throttle valves to be opened. This increases the power generated by the machine, but it also results in the boiler pressure falling, and when this happens the boiler control system reacts by increasing the firing rate. This is all right as far as it goes since, quite correctly, it increases the boiler steaming rate to meet the increase in demand. However, as the firing change comes into effect and the steam pressure rises, the amount of power that is being generated also increases. But as it has already been increased to meet the demand--and in fact may have already done so--the power generated can overshoot the target, causing the throttle valves to start closing again, which raises the boiler pressure..., and so on.

1-4-2-Response of the turbine-following system In the simplest version of the turbine-following system the boiler firing rate, and the rate of air and feed-water admission etc., are all fixed (or, at least, held at a set value, which may be adjusted from time to time by the boiler operator), and the turbine throttle valves are modulated to keep the steam pressure constant. However, when the fuel, air and water flows of a boiler are held at a constant value the amount of steam that is generated will not, in general, remain constant, mainly because of the inevitable variations that will occur in parameters such as the calorific value of the fuel, the temperature of the feed water etc. In the simple turbine-following system, these variations are corrected by modulation of the turbine throttle valve to maintain a constant steam pressure, but this results in variations in the power generated by the turbine.

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Because the steam-generation rate of its boiler is not automatically adjusted to meet an external demand, a plant operating under the control of a simple turbine-following system will generate amounts of power that do not relate to the short-term needs of the grid system. Such a plant is therefore incapable of operating in a frequencysupport mode, although this mode of operation may be used where it is not easy, or desirable, to adjust the fuel input, for instance in industrial waste-incineration plants.

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2-Boiler components control 2-1-Combustion, burner and draught control Naturally, in a fired boiler the control of combustion is extremely critical. In order to maximize operational efficiency combustion must be accurate, so that the fuel is consumed at a rate that exactly matches the demand for steam, and it must be executed safely, so that the energy is released without risk to plant, personnel or environment. Control of combustion is achieved through controlling air and fuel flow to burner. Theoretically speaking, burner should keep the ratio between fuel and air constant along all load range to achieve stoichiometric mixing between them. Unfortunately, when the realities of practical plant are involved, the situation once again becomes far more complex than this simple analysis would suggest.

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If amount of excess air is increase over a certain limit, it causes loss in efficiency. The reduction in efficiency is due to losses which are composed of the heat wasted in the exhaust gases and the heat which is theoretically available in the fuel, but which is not burned. As the excess-air level increases, the heat lost in the exhaust gases increases, while the losses in unburned fuel reduce (the shortage of oxygen at the lower levels increasing the degree of incomplete combustion that occurs). The sum of these two losses, plus the heat lost by radiation from hot surfaces in the boiler and its pipe work, is identified as the total loss. The figure above shows that operation of the plant at the point identified at 'A' will correspond with minimum losses, and from this it may be assumed that this is the point to which the operation of the combustion-control system should be targeted. However, in practice air is not evenly distributed within the furnace. For example, operational considerations require that a supply of cooling air is provided for idle burners and flame monitors, to prevent them being damaged by heat from nearby active burners and by general radiation from the furnace. Air also enters the combustion chamber through leaks, observation ports, soot-blower entry points and so on. The sum of all this is referred to as 'tramp air' or 'setting leakage'. If this is included in the total being supplied to the furnace, and if that total is apportioned to the total amount of fuel being fired, the implication is that some burners (at least) will be deprived of the air they need for the combustion of their fuel. In other words, the correct amount of air is being provided in total, but it is going to places where it is not available for the combustion process. Operation of the firing system must take these factors into account, and from then on the system can apportion the fuel and air flows. If these are maintained in a fixed relationship with each other over the full range of flows, the amount of excess air will be fixed over the entire range.

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2-1-1-Burners control systems 2-1-1-1-A simple system: "parallel control" The easiest way of maintaining a relationship between fuel flow and air flow is to use a single actuator to position a fuel-control valve and an air control damper in parallel with each other as shown in figure below. Here, the opening of an air-control damper is mechanically linked to the opening of a fuel control valve to maintain a defined relationship between fuel flow and air flow. This system is employed in very small boilers, and we can achieve a non-linear relationship between valve opening and damper opening to be determined by the shape of a cam, with a range of cams offering a variety of relationships.

Although this simple system may be quite adequate for very small boilers burning fuels such as oil or natural gas, its deficiencies become increasingly apparent as the size of the plant increases. System problems 1-It assumes that for a given opening of fuel valve or air damper we get a certain amount of flow and this is not true as flow depends also on pressure difference between valves sides, also flow will depends on properties of fuel and air like density.

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2- Another problem is that the response times of the fuel and air systems are never identical. Therefore, if a sudden load-change occurs and the two controlling devices are moved to predetermined openings, the flows through them will react at different rates. With an oil-fired boiler, a sudden increase in demand will cause the fuel flow to increase quickly, but the air system will be slower to react. As a result, if the fuel/air ratio was correct before the change occurred, the firing conditions after the change will tend to become fuel-rich until the air system has had time to catch up. This causes characteristic puffs of black smoke to be emitted as unburned fuel is ejected to the chimney. On a load decrease the reverse happens, and the mixture in the combustion chamber becomes air-rich. The resulting high oxygen content could lead to corrosion damage to the metalwork of the boiler, and to unacceptable flue-gas emissions.

2-1-1-2-Flow ratio control The first approach to overcoming the limitations of a simple 'parallel' system is to measure the flow of the fuel and the air, and to use closed-loop controllers to keep them in track with each other, as shown by the two configurations of figure shown next page. In each of these systems the master demand (not shown) is used to set the quantity of one parameter being admitted to the furnace, while a controller maintains an adjustable relationship between the two flows (fuel and air). In the system shown in Figure a a gain block or amplifier in one of the flow-signal lines is used to adjust the ratio between the two flows. As the gain (g) of this block is changed, it alters the slope of the fuel-flow/airflow characteristic, changing the amount of excess air that is present at each flow. Note that when the gain is fixed, the amount of excess air is the same for all flows, as shown by the horizontal line. In practice, this situation would be impossible to achieve, since some air inevitably leaks into the furnace, with the result that the amount of excess air is proportionally greater at low flows than high flows.

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The system shown in figure in previous page shows a different control arrangement working with the same idealized plant (i.e. one with no air leaking into the combustion chamber). Here, instead of a gain function, a bias is added to one of the signals. The effect of this is that a fixed surfeit of air is always present and this is proportionally larger at the smaller flows, with the result that the amount of excess air is largest at small flows, as shown. Changing the bias signal (b) moves the curve bodily as shown. Each of these control configurations has been used in practical plant, although the version with bias (Figure 5.3b) exacerbates the effects of tramp air and therefore tends to be confined to smaller boilers. The arrangement shown in figure (a) therefore forms the basis of most practical fuel/air ratio control systems. In these illustrations it has been assumed that the master demand is fed to the fuel valve, leaving the air-flow controller to maintain the fuel/air ratio at the correct desired value. When this is done, the configuration is known as a 'fuel lead' system since, when the load demand changes, the fuel flow is adjusted first and the controller then adjusts the air flow to match the fuel flow, after the latter has changed. It doesn't have to be done this way. Instead, the master demand can be relayed to the air-flow controller, which means that the task of maintaining the fuel/air ratio is then assigned to the fuel controller. For obvious reasons this is known as an 'air-lead' system. So, Fuel lead system is the system which manipulates fuel flow according to load and let the controller adjust the amount of air flow to achieve the predetermined air to fuel ratio. So, air lead system is the system which manipulates air flow according to load and let the controller adjust the amount of fuel flow to achieve the predetermined air to fuel ratio.

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Comparing the "fuel-lead' and 'air-lead' approaches Of the two alternatives described above, the fuel-lead version will provide better response to load changes, since its action does not depend on the slower-responding plant that supplies combustion air to the furnace. However, because of this, the system suffers from a tendency to produce fuel-rich conditions on load increases and fuel-lean conditions on decreases in the load. Disadvantages of working in rich fuel region Operating in the fuel-rich region raises the risk of unburned fuel being ignited in an uncontrolled manner, possibly causing a furnace explosion. Disadvantages of working with too much excess air Whereas operating with too much excess air, while not raising the risk of an uncontrolled fire or an explosion, does cause a variety of other problems, including back-end corrosion of the boiler structure, and undesirable stack emissions. The air-lead system is slow to respond because it requires the draught plant to react before the fuel is increased. Although this avoids the risk of creating fuel-rich conditions as the load increases, it remains prone to such a risk as the load decreases “as the air takes time to be reduced, hence the fuel will be injected during this period which will make a fuel rich mixture”. However, the hazard is less than for the fuel lead system. Disadvantages of both systems A further limitation of these systems (in either the fuel-lead or air-lead version) is that they offer no protection against equipment failures, since these cannot be detected and corrected without special precautions being taken. For example, in the fuel-lead version, if the fuel-flow transmitter fails in such a way that it signals a lower flow than the amount that is actually being delivered to the furnace, the fuel/air ratio controller will attempt to reduce the supply of combustion air to match the erroneous measurement. This will cause the combustion conditions to become fuel rich, with the attendant risk of an explosion. Conversely, if the fuelflow transmitter in the air-lead system fails low, the fuel controller will attempt to Boiler Operation And Control

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compensate for the apparent loss of fuel by injecting more fuel into the furnace, with similar risks.

2-1-1-3-Cross-limited control

Figure above shows the principles of the cross-limited combustion control system. Individual flow-ratio controllers (FRC) (7, 8) are provided for the fuel and air systems, respectively. The effect of the fuel/air ratio adjustment block (4) is to modify the airflow signal in accordance with the required fuel/air relationship. (FT) is a flow transmitter to give a value for actual flow for fuel and air (2 & 3). Because fuel flow and air flow are each measured as part of a closed loop, the system compensates for any changes in either of these flows that may be caused by external Boiler Operation And Control

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factors. For this reason it is sometimes referred to as a 'fully metered' system. The effect of the fuel/air ratio adjustment block (4) is to modify the air-flow signal in accordance with the required fuel/air relationship. How this system works? So far, the configuration performs similarly to the basic systems in previous section. The difference becomes apparent when the maximum and minimum selectors are brought into the picture (components 5 & 6). Remembering the problems of the differing response-rates of the fuel and air supply systems, consider what happens when the master demand signal suddenly requests an increase in firing. Assume that, prior to that instant; the fuel and air controllers have been keeping their respective controlled variable in step with the demand, so that the fuel-flow and modified airflow signals are each equal to the demand signal. When the master demand signal suddenly increases, it now becomes larger than the fuel-flow signal and it is therefore ignored by the minimum-selector block (5) which instead latches onto the modified air-flow signal (from item 4). The fuel controller now assumes the role of fuel/air ratio controller, maintaining the boiler's fuel input at a value that is consistent with the air being delivered to the furnace. The air flow is meanwhile being increased to meet the new demand, since the maximum-selector block (6) has latched onto the rising master signal. On a decrease in load, the system operates in the reverse manner. The minimumselector block locks onto the collapsing master and quickly reduces the fuel flow, while the maximum-selector block chooses the fuel flow signal as the demand for the air-flow controller (8), which therefore starts to operate as the fuel/air ratio controller, keeping the air flow in step with the fuel flow. Analysis of the system will show that it is much better able to deal with plant or control and instrumentation equipment failures. For example, if the fuel valve fails open, the air controller will maintain adequate combustion air to meet the quantity of fuel being supplied to the combustion chamber. This may result in over firing but it cannot cause fuel-rich conditions to be created in the furnace. Similarly, if the fuelflow transmitter fails low, although the fuel controller will still attempt to

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compensate for the apparent loss of fuel, the air flow controller will ensure that adequate combustion air is supplied.

2-1-1-4-Multiple-burner systems The systems that have been described so far are based on the adjustment of the total quantity of fuel and air that is admitted to the combustion chamber. This approach may be sufficient with smaller boilers, where adjustment of a single fuel valve and air damper is reasonable, but larger units will have a multiplicity of burners, fuel systems, fans, dampers and combustion-air supplies. In such cases proper consideration has to be given to the distribution of air and fuel to each burner or, if this is not practical, to small groups of burners. The concept of individually controlling air registers to provide the correct fuel/air ratio to each burner of a multi burner boiler has been implemented, but in most practical situations the expense of the instrumentation cannot be justified. Oil and gas burners can be operated by maintaining a defined relationship between the fuel pressure and the differential pressure across the burner air register (rather than proper flow measurements), but even with such economies the capital costs are high and the payback low. The need to provide a modulating actuator for each air register adds further cost. A more practical option is to control the ratio of fuel and air that flows to groups of burners. Figure shown next page shows how the principles of a simple cross limited system are applied to a multi burner oil-fired boiler. The plant in this case comprises several rows of burners, and the flow of fuel oil to each row is controlled by means of a single valve. The combustion air is supplied through a common wind box, and the flow to the firing burners is controlled by a single set of secondary-air dampers.

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In most respects the arrangement closely resembles the basic cross limited system explained in previous section, with the oil flow inferred from the oil pressure at the row. A function generator is used to convert the pressure signal to a flow-per-burner signal, which is then multiplied by a signal representing the number of burners firing in that row, to yield a signal representing the total amount of oil flowing to the burners in the group. Working with multiple fuels The control systems of boilers burning several different types of fuel have to recognize the heat-input contribution being made at any time by each of the fuels, Boiler Operation And Control

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and the arrangements become more complicated for every additional fuel that is to be considered.

Figure above shows a system for a boiler burning oil and gas. The similarities to the simple cross-limited system are very apparent, as are the commonalities with the fuelcontrol part of the multi burner system (shown within the chain-dotted area of Figure 5.9). Boiler Operation And Control

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The cross-limiting function is performed at the minimum-selector block (5) which continuously compares the master demand with the quantity of combustion air flowing to the common wind box of the burner group. The gain block (6) translates the air flow into a signal representing the amount of fuel whose combustion can be supported by the available secondary air. The selected signal (the load demand or the available air) ultimately forms the desired value of both the gas and oil closed-loop controllers. But, before it reaches the relevant controller a value is subtracted from it, which represents the heat contributed by the other fuel (converted to the same heat/m s value as the fuel being controlled). The conversion of oil flow to equivalent gas flow is performed in a function generator (10), while the other conversion is performed in another such block (14). Each of the two summator units (11 and 13) algebraically subtracts the 'other-fuel’ signal from the demand. Note that, in the case of this system, the gas pressure signal is compensated against temperature variations, since the pressure/flow relationship of the gas is temperature-dependent. As before, each fuel-flow signal represents the flow per burner and so it has to be multiplied by the number of burners in service in order to represent the total fuel flow. These diagrams are highly simplified, and in practice it is necessary to incorporate various features such as interlocks to prevent over firing and to isolate one or other of the pressure signals when no burner is firing that fuel. (This is because a pressure signal will exist even when no firing is taking place.)

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2-1-2-Draught control We will understand draught control via inspecting draught system components, layout and operation. In the following section we shall see how air is delivered to the furnace at the right conditions of flow and temperature, starting with the auxiliary plant that warms the air and moving on to the types of fan employed in the draught plant. The air heater In a simple-cycle plant, air is delivered to the boiler by one or more forced draught fans and the products of combustion are extracted from it by induced draught fans as shown in figure below.

Figure above shows this plant in a simplified form, and illustrates how the heat remaining in the exhaust gases leaving the furnace is used to warm the air being fed to the combustion chamber. This function is achieved in an air heater, which can be Boiler Operation And Control

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either regenerative, where an intermediate medium is used to transfer the heat from the exhaust gases to the incoming air, or recuperative, where a direct heat transfer is used across a dividing partition. In the regenerative type, air and exhaust may mix at a certain limit; this is referred to as ‘air leakage’. Leakage happens across the circumferential, radial and axial seals, as well as at the hub. These leakages are minimized when the plant is first constructed, but become greater as wear occurs during prolonged usage. When the sheer physical size of the air heater is considered it will be appreciated that these leakages can become significant.

2-1-2-1-Types of fan according to function Here, classification is according to function, there are 3 types;  Forced draught fan  Induced draught fan  Booster fan

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In addition to the FD and ID fans mentioned above, another application for large fans in a power-station boiler is where it is necessary to overcome the resistance presented by plant in the path of the flue gases to the stack. In some cases, environmental legislation has enforced the fitting of flue gas desulphurisation equipment to an existing boiler. This involves the use of absorbers and/or bag filters, plus the attendant ducting, all of which present additional resistance to the flow of gases. In this case this resistance was not anticipated when the plant was originally designed, so it is necessary to fit additional fans to overcome the draught losses. These are called 'booster fans'.

2-1-2-2-Types of fans according to working principle In power plant, we use 2 types of fans “according to fan design and working principles”  Centrifugal fans  Axial flow fans

2-1-2-2-1-Centrifugal fans The blades are set radially on the drive shaft with the air or flue gas directed to the centre and driven outwards by centrifugal force.

2-1-2-2-2-Axial-flow fans The air or gas is drawn along the line of the shaft by the screw action of the blades. Whereas the blades of a centrifugal fan are fixed rigidly to the shaft, the pitch of axialflow fan blades can be adjusted. This provides an efficient means of controlling the fan's throughput, but requires careful design of the associated control system because of a phenomenon known as 'stall', which will now be described.

2-1-2-3-Fan control constrains There is some constrains for fan operation, this constrains are related to fan theory of operation and its design, these limitation is explained below

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2-1-2-3-1-The stall condition The angular relationship between the air flow impinging on the blade of a fan and the blade itself is known as the 'angle of attack'. In an axial-flow fan, when this angle exceeds a certain limit, the air flow over the blade separates from the surface and centrifugal force then throws the air outwards, towards the rim of the blades. This action causes a build-up of pressure at the blade tip, and this pressure increases until it can be relieved at the clearance between the tip and the casing. Under this condition the operation of the fan becomes unstable, vibration sets in and the flow starts to oscillate. The risk of stall increases if a fan is oversized or if the system resistance increases excessively. For each setting of the blades there is a point on the fan characteristic beyond which stall will occur. If these points are linked, a 'stall line' is generated as shown in figure below and if this is built into the plant control system (DCS) it can be used to warn the operator that the condition is imminent and then to actively shift operation away from the danger region. The actual stall-line data for a given machine should be provided by the fan manufacturer.

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2-1-2-3-2-Centrifugal fan surge

The stall condition affects only axial-flow fans. However, centrifugal fans are subject to another form of instability. If they are operated near the peak of their pressure/flow curve a small movement either way can cause the pressure to increase or decrease unpredictably. The point at which this phenomenon occurs is known as the 'surge limit' and it is the minimum flow at which the fan operation is stable.

2-1-2-4-Air flow control methods After knowing about fans and their limitation, we will discuss methods of fan control and characteristics of each control method. There are 3 methods of fan control;  Damper  Fan speed  Blade angle

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1-Fan damper

The simplest form of damper consists of a hinged plate that is pivoted at the centre so that it can be opened or closed across the duct. This provides a form of draught control but it is not very linear and it is most effective only near the closed position. Once such a damper is more than about 40- 60% open it can provide very little additional control. Another form of damper comprises a set of linked blades across the duct (like a Venetian blind). Such multi bladed dampers are naturally more expensive and more complex to maintain than single-bladed versions, but they offer better linearity of control over a wider range of operation.

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2-1-2-4-2-Vane control

The second form of control is by the adjustment of vanes at the fan inlet. Such vanes are operated via a complex linkage which rotates all the vanes through the same angle in response to the command signal from the DCS.

2-1-2-4-3-Variable-speed drives Finally, control of fan throughput can be achieved by the use of variable speed motors (or drives). These may involve the use of electronic controllers which alter the speed of the driving motor in response to demand signals from the DCS or they can be hydraulic couplings or variable-speed gearboxes, either of which allows a fixed-speed motor to drive the fan at the desired speed. Variable speed drives offer significant advantages in that they allow the fan to operate at the optimum speed for the required throughput of air or gas, whereas dampers or vanes control the flow by restricting it, which means that the fan is attempting to deliver more flow than is required.

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As we know, in a fired boiler, the air required for combustion is provided by one or more fans and the exhaust gases are drawn out of the combustion chamber by an additional fan or set of fans. On boilers with retro-fitted flue-gas desulphurisation plant, additional booster fans may also be provided. The control of all these fans must ensure that an adequate supply of air is available for the combustion of the fuel and that the combustion chamber operates at the pressure determined by the boiler designer. All of the fans also have to contribute to the provision of another important function purging of the furnace in all conditions-when a collection of unburned fuel or combustible gases could otherwise be accidentally ignited. Such operations are required prior to light-off of the first burner when the boiler is being started, or after a trip. The control systems for the fans have to be designed to meet the requirements of start-up, normal operation and shut-down, and to do so in the most efficient manner possible, because the fans may be physically large and require a large amount of power for their operation (several MW in some cases). In addition, as we know, the performance constraints of the fans, such as surge and stall, have to be recognized, if necessary by the provision of special control functions or interlocks.

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2-1-2-5-Draught system duties The main duty of draught system is to maintain the furnace draught. Apart from supplying air to support combustion, the FD fans have to operate in concert with the ID fans to maintain the furnace pressure at a certain value. The heavy solid line of figure shown below shows the pressure profile through the various sections of a typical balanced-draught boiler system. It shows the pressure from the point where air is drawn in, to the point where the flue gases are exhausted to the chimney, and demonstrates how the combustion chamber operates at a slightly negative pressure, which is maintained by keeping the FD and ID fans in balance with each other.

If that balance is disturbed the results can be extremely serious. Such an imbalance can be brought about by the accidental closure of a damper or by the sudden loss of all flames. It can also be caused by mal operation of the FD and ID fans. The dashed line on the diagram shows the pressure profile under such a condition, which known as an 'implosion'.

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The results of an implosion are extremely serious because, even though the pressures involved may be small, the surfaces over which they are applied are very large and the forces exerted become enormous. Such an event would almost certainly result in major structural damage to the plant.

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2-2-Feed water control system Control of feed water is executed via feed water regulator, types of feed water regulators are presented in the following sections

2-2-1-Feedwater Regulators A boiler feedwater regulator automatically controls the water supply so that the level in the boiler drum is maintained within desired limits. This automatic regulator adds to the safety and economy of operation and minimizes the danger of low or high water. Uniform feeding of water prevents the boiler from being subjected to the expansion strains that would result from temperature changes produced by irregular water feed. The danger in the use of a feedwater regulator lies in the fact that the operator may be entirely dependent on it. It is well to remember that the regulator, like any other mechanism, can fail; continued attention is necessary.

2-2-1-1-Oldest feed water regulator

It consists of a simple float attached to lever to control feed water flow and to keep level constant as shown above. Next generation employs the float in a different manner as shown in figure a.

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For high-capacity boilers and those operating at high pressure, a pneumatic or electrically operated feedwater control system is used. There are basically three types of feedwater-control systems: (1) Single element, (2) two element, and (3) three element.

2-2-1-2-Single-element control

This uses a single control loop that provides regulation of feedwater flow in response to changes in the drum water level from its set point. The measured drum level is compared to its set point, and any error produces a signal that moves the feedwater control valve in proper response. Boiler Operation And Control

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Single-element control will maintain a constant drum level for slow changes in load, steam pressure, or feedwater pressure. However, because the control signal satisfies the requirements of drum level only, wider drum-level variation results.

2-2-1-3-Two-element control

This uses a control loop that provides regulation of feedwater flow in response to changes in steam flow, with a second control loop correcting the feedwater flow to ensure the correct drum water level. The steam flow control signal anticipates load changes and begins control action in the proper direction before the drum-level control loop acts in response to the drum water level. The drum-level measurement corrects for any imbalance between the drum water level and its set point and provides the necessary adjustment to cope with the “swell and shrink” characteristics of the boiler.

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2-2-1-4-Three-element control This uses a predetermined ratio of feedwater flow input to steam flow output to provide regulation of feedwater flow in direct response to boiler load. The threeelement control regulates the ratio of feedwater flow input to steam flow output by establishing the set point for the drum-level controller. Any change in the ratio is used to modify the drum-level set point in the level controller, which regulates feedwater flow in direct response to boiler load. This is the most widely used feedwater-control system.

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2-2-2-Types of feed water regulators 2-2-2-1-Thermohydraulic type A thermohydraulic, or generator-diaphragm, type of boiler feedwater regulator is shown in Figure b. Connected to the radiator is a small tube running to a diaphragm chamber. The diaphragm in turn operates a balanced valve in the feedwater line. The inner tube is connected directly to the water column and contains steam and water. The outside compartment, connecting the tube and valve diaphragm, is filled with water. This water does not circulate. Heat is radiated from it by means of fins attached to the radiator. Water in the inner tube of the regulator remains at the same level as that in the boiler. When the water in the boiler is lowered, more of the regulator tube is filled with steam and less with water. Since heat is transferred faster from steam to water than from water to water, extra heat is added to the confined water in the outer compartment. The radiating-fin surface is not sufficient to remove the heat as rapidly as it is generated, so the temperature and pressure of the confined water are raised. This pressure is transmitted to the balanced-valve diaphragm to open the valve, admitting water to the boiler. When the water level in the boiler is high, this operation is reversed.

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2-2-2-2-Thermostatic expansion-tube-type The thermostatic expansion-tube-type feedwater regulator is shown in Figure c. Because of expansion and contraction, the length of the thermostatic tube changes and positions the regulating valve with each change in the proportioned amount of steam and water.

A two element steam-flow-type feedwater regulator shown in the above figure combines a thermostatic expansion tube operated from the change in water level in the drum as one element with the differential pressure across the superheater as the second element. The two combined operate the regulating valve. An air-operated three-element feedwater control (Fig. 6.12a) combines three elements to control the water level. Water flow is proportioned to steam flow, with drum level as the compensating element; the control is set to be insensitive to the level. In operation, a change in position of the metering element positions a pilot valve to vary the air loading pressure to a standatrol (self-standardizing relay). The resulting position assumed by the standatrol provides pressure to operate a pilot valve attached to the feedwater regulator. The impulse from the standatrol passes through a hand-automatic selector valve, permitting either manual or automatic operation. The hand-wheel jack permits manual adjustment of the feedwater valve if remote control is undesirable.

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2-3-Steam temperature control Why steam temperature control is needed: The rate at which heat is transferred to the fluid in the tube banks of a boiler or HRSG will depend on the rate of heat input from the fuel or exhaust from the gas turbine. This heat will be used to convert water to steam and then to increase the temperature of the steam in the superheat stages. In a boiler, the temperature of the steam will also be affected by the pattern in which the burners are fired, since some banks of tubes pick up heat by direct radiation from the burners. In both types of plant the temperature of the steam will also be affected by the flow of fluid within the tubes, and by the way in which the hot gases circulate within the boiler. As the steam flow increases, the temperature of the steam in the banks of tubes that are directly influenced by the radiant heat of combustion starts to decrease as the increasing flow of fluid takes away more of the heat that falls on the metal. Therefore the steam-temperature/steam-flow profile for this bank of tubes shows a decline as the steam flow increases. On the other hand, the temperature of the steam in the banks of tubes in the convection passes tends to increase because of the higher heat transfer brought about by the increased flow of gases, so that this temperature/ flow profile shows a rise in temperature as the flow increases. By combining these two characteristics, the one rising, the other falling, the boiler designer will aim to achieve a fairly flat temperature/flow characteristic over a wide range of steam flows. No matter how successfully this target is attained, it cannot yield an absolutely flat temperature/flow characteristic. Without any additional control, the temperature of the steam leaving the final superheater of the boiler or HRSG would vary with the rate of steam flow, following what is known as the 'natural characteristic' of the boiler. The shape of this will depend on the particular design of plant, but in general, the temperature will rise to a peak as the load increases, after which it will fall. The steam turbine or the process plant that is to receive the steam usually requires the temperature to remain at a precise value over the entire load range, and it is mainly for this reason that some dedicated means of regulating the temperature must be provided. Since different banks of tubes are affected in different ways by the Boiler Operation And Control

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radiation from the burners and the flow of hot gases, an additional requirement is to provide some means of adjusting the temperature of the steam within different parts of the circuit, to prevent any one section from becoming overheated. Before looking at the types of steam-temperature control systems that are applied, it will be useful to examine some of the mechanisms which are employed to regulate the temperature according to the controller's commands. Depending on whether or not the temperature of the steam is lowered to below the saturation point the controlling devices are known as attemperators or desuperheaters. (Strictly speaking, the correct term to use for a device which reduces the steam temperature to a point which is still above the saturation point is an attemperator, while one that lowers it below the saturation point may be referred to either as an attemperator or a desuperheater. However, in common engineering usage both terms are applied somewhat indiscriminately.)

2-3-1-The spray water attemperators One way of adjusting the temperature of steam is to pump a fine spray of comparatively cool water droplets into the vapour. With the resulting intermixing of hot steam and cold water the coolant eventually evaporatesso that the final mixture comprises an increased volume of steam at a temperature which is lower than that prior to the water injection point. This cooling function is achieved in the attemperator. The attemperator is an effective means of lowering the temperature of the steam, though in thermodynamic terms it results in a reduction in the performance of the plant because the steam temperature has to be raised to a higher value than is needed, only to be brought down to the correct value later, by injecting the spray water. Although the inherent design of the attemperation system may, in theory, permit control to be achieved over a very wide range of steam flows, it should be understood that the curve of the boiler's natural characteristic will restrict the load range over which practical temperature control is possible, regardless of the type of attemperator in use. It is not unusual for the effective temperature-control range of a boiler to be between only 75% and 100% of the boiler's maximum continuous rating

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(MCR). This limitation is also the result of the spray-water flow being a larger proportion of the steam flow at low loads.

2-3-1-1-The mechanically atomised attemperator Various forms of spray attemperator are employed. Figure 1 shows a simple design where the high-pressure cooling water is mechanically atomised into small droplets at a nozzle, thereby maximising the area of contact between the steam and the water. With this type of attemperator the water droplets leave the nozzle at a high velocity and therefore travel for some distance before they mix with the steam and are absorbed. To avoid stress-inducing impingement of cold droplets on hot pipework, the length of straight pipe in which this type of attemperator needs to be installed is quite long, typically 6 m or more. With spray attemperators, the flow of cooling water is related to the flow rate and the temperature of the steam, and this leads to a further limitation of a fixed-nozzle attemperator. Successful break-up of the water into atomised droplets requires the spray water to be at a pressure which exceeds the steam pressure at the nozzle by a certain amount (typically 4 bar). Because the nozzle presents a fixed-area orifice to the spray water, the pressure/flow characteristic has a square-law shape, resulting in a restricted range of flows over which it can be used (this is referred to as limited turn-down or rangeability). The turn-down of the mechanically atomised type ofattemperator is around 1.5 : 1. The temperature of the steam is adjusted by modulating a separate spray-water control valve to admit more or less coolant into the steam. Because of the limitations of the single nozzle, the accuracy of control that is possible with this type of attemperator is no greater than + 8.5 °C.

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Figure 1 Mechanically atomised desuperheater

2-3-1-2-The variable-area attemperator One way of overcoming the limitations of a fixed nozzle in an attemperator is to use an arrangement which changes the profile as the throughput of spray water alters. Figure 2 shows the operating principle of a variable area, multinozzle attemperator. This employs a sliding plug which is moved by an actuator, allowing the water to be injected through a greater or smaller number of nozzles. With this type of device, the amount of water injected is regulated by the position of the sliding plug, a separate spray-water control valve is therefore not needed. Adequate performance of this type of attemperator depends on the velocity of the vapour at the nozzles being high enough to ensure that the coolant droplets remain in suspension for long enough to ensure their absorption by the steam. For this reason, and also to provide thermal protection for the pipework in the vicinity of the nozzles, a thermal liner is often included in the pipe extending from the plane of the nozzles to a point some distance downstream.

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The accuracy of control and the turndown range available from a multi-nozzle attemperator is considerably greater than that of a single nozzle version, allowing the steam temperature to be controlled to + 5.5°C over a flow range of 40: 1.

Figure 2 Principle of a multi nozzle desuperheater

2-3-1-3-The variable-annulus desuperheater Another way of achieving accurate control of the steam temperature over the widest possible dynamic range is provided by the variable-annulus desuperheater (VAD) (produced by Copes-Vulcan Limited, Road Two, Winsford Industrial Estate, Winsford, Cheshire, CW7 3QL.). Here, the approach contour of the VAD head is such that when the inlet steam flows through an annular ring between the spray head and the inner wall of the steam pipe its velocity is increased and the pressure slightly reduced. The 140 Power-plant control and instrumentation coolant enters at this point and undergoes an instant increase in velocity and a decrease in pressure, causing it to vapourise into a micron-thin layer which is stripped offthe edge of the spray head and propelled downstream. The stripping action acts as a barrier which prevents the coolant from impinging on the inner wall of the steam pipe. The downstream portion of the VAD head is contoured, creating a vortex zone into which any unabsorbed coolant is drawn, Boiler Operation And Control

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exposing it to a zone of low pressure and high turbulence, which therefore causes additional evaporation. Due to the Venturi principle, the pressure of the cooled steam is quickly restored downstream of the vena contracta point, resulting in a very low overall loss of pressure. An advantage of the VAD is that, due to the coolant injection occurring at a point where the steam pressure is lowered, the pressure of the spray water does not have to be significantly higher than that of the steam.

2-3-1-4-Other types of attemperator At least two other designs of attemperator will be encountered in power station applications. The vapour-atomising design mixes steam with the cooling water, thus ensuring more effective break-up of the water droplets and shrouding the atomised droplets in a sheath of steam to provide rapid attemperation. Variable-orifice attemperators include a freely floating plug which is positioned above a fixed seat--a design that generates high turbulence and more efficient attemperation. The coolant velocity increases simultaneously with the pressure drop, instantly vaporising the liquid. Because of the movement of the plug, the pressure drop across the nozzle remains constant (at about 0.2 bar). The design of this type of attemperator is so efficient that complete mixing of the coolant and the steam is provided within 3 to 4 m of the coolant entry point, and the temperature can be controlled to __+ 2.5 °C, theoretically over a turndown range of 100: 1. Because the floating plug moves against gravity, this type of attemperator must be installed in a vertical section of pipe with the steam through it travelling in an upward direction. However, because of the efficient mixing of steam and coolant, it is permissible to provide a bend almost immediately after the device. Figure 3 shows a typical installation.

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Figure 3 Variable-orifice attemperator installation

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Location of temperature sensors: Because the steam and water do not mix immediately at the plane of the nozzle or nozzles, great care must be taken to locate the temperature sensor far enough downstream of the attemperator for the measurement to accurately represent the actual temperature of the steam entering the next stage of tube banks. Direct impingement of spray water on the temperature sensor will result in the final steam temperature being higher than desired. Figure 4 shows a typical installation, in this case for a variable-annulus desuperheater.

Figure 4 a typical installation

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2-3-2-Temperature control with tilting burners The burning fuel in a corner-fired boiler forms a large swirling fireball which can be moved to a higher or lower level in the furnace by tilting the burners upwards or downwards with respect to a mid position. The repositioning of the fireball changes the pattern of heat transfer to the various banks of superheater tubes and this provides an efficient method of controlling the steam temperature, since it enables the use of spray water to be reserved for fine-tuning purposes and for emergencies. In addition, the tilting process provides a method of controlling furnace exit temperatures. With such boilers, the steam temperature control systems become significantly different from those of boilers with fixed burners. The boiler designer is able to define the optimum angular position of the burners for all loads, and the control engineer can then use a function generator to set the angle of tilt over the load range to match this characteristic. A temperature controller trims the degree of tilt so that the correct steam temperature is attained.

2-3-3-Controlling the temperature of reheated steam In boilers with reheat stages, changes in firing inevitably affect the temperature of both the reheater and the superheater. If a single control mechanism were to be used for both temperatures the resulting interactions would make control-system tuning difficult, if not impossible, to optimize. Such boilers therefore use two or more methods of control. Because of the lower operating pressure of reheat steam systems, the thermodynamic conditions are significantly different from those of superheaters, and the injection of spray water into the reheater system has an undue effect on the efficiency of the plant. For this reason, it is preferable for the reheat stages to be controlled by tilting burners (if these are available) or by apportioning the flow of hot combustion gases over the various tube banks. However, if the superheat temperature is controlled by burner tilting, gas apportioning or spray attemperation must then be used for the reheat stages. In boilers with fixed burners, steam-temperature control may be achieved by adjusting the opening of dampers that control the flow of the furnace gases across the Boiler Operation And Control

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various tube banks. In some cases two separate sets of dampers are provided: one regulating the flow over the superheater banks, the other controlling the flow over the reheater banks. Between them, these two sets of dampers deal with the entire volume of combustion gases passing from the furnace to the chimney. If both were to be closed at the same time, the flow of these gases would be severely restricted, leading to the possibility of damage to the structure due to over pressurization. For this reason the two sets are controlled in a so-called 'split-range' fashion, with one set being allowed to close only when the other has fully opened. These dampers provide the main form of control, but the response of the system is very slow, particularly with large boilers, where the temperature response to changes in heat input exhibits a second-order lag of almost two minutes' duration. For this reason, and also to provide a means of reducing the temperature of the reheat steam in the event of a failure in the damper systems, spray attemperation is provided for emergency cooling. The spray attemperator is shut unless the temperature at the reheater outlet reaches a predetermined high limit. When this limit is exceeded, the spray valve is opened. In this condition, the amount of water that is injected is typically controlled in relation to the temperature at the reheater inlet, to bring the exit temperature back into the region where gas-apportioning or burner tilting can once again be effective. The relationship between the cold reheat temperature and the required spray water flow can be defined by the boiler designer or process engineer. If a turbine trip occurs the reheat flow will collapse. In this situation the reheat sprays must be shut immediately in order to prevent serious damage being caused by the admission of cold spray water to the turbine. Spray attemperators for reheat applications At first, it may seem that reheat spray-water attemperator systems should be similar to those of the superheater. This is untrue, because reheat attemperators have to cope with the lower steam pressure in this section of the boiler, which renders the pressure of the water at the discharge of the feed pumps too high for satisfactory Boiler Operation And Control

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operation. Although a pressure-reducing valve could be introduced into the spraywater line, this would be an expensive solution whose long-term reliability would not be satisfactory because of the severe conditions to which such a valve would be subjected. A better solution would be to derive the supply from the feed-pump inlet. In some cases, even this is ineffective, and separate pump sets have to be provided for the reheat sprays. (A) Gas recycling Where boilers are designed for burning oil, or oil and coal in combination, they are frequently provided with gas-recirculation systems, where the hot gases exiting the later stages of the boiler are recirculated to the bottom part of the furnace, close to the burners. This procedure increases the mass-flow of gas over the tube banks, and therefore increases the heat transfer to them. Because the gas exiting the furnace is at a low pressure, fans have to be provided to ensure that the gas flows in the correct direction. Controlling the flow of recycled gases provides a method of regulating the temperature of the superheated and reheated steam, but interlocks have to be provided to protect the fan against hightemperature gases flowing in a reverse direction from the burner area if the fan is stopped or if it trips.

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2-4-Boiler pressure control In a typical generating station will perform the following functions:  To control boiler pressure under normal operating conditions to a specified set point.  To allow warm-up or cool-down of the heat transport system at a controlled rate. Since, under saturated conditions, steam pressure and temperature are uniquely related, boiler pressure is used to indicate the balance between reactor heat output and steam loading conditions. Steam pressure measurement is used since it provides a faster response than a temperature measurement.

The Boiler Pressure Control is a digital control loop application with a sampling period every 2 seconds.

Basic Principles A steam generator (boiler) is simply a heat exchanger and as such it obeys the standard heat transfer relationship from one side of the boiler (tubes side) to the other (shell-side). Standard Heat transfer relationship can be described as:

Q = U. A. D T where: Q = the

rate of heat exchange from the HTS to the boiler water (kJ/s).

U = heat transfer coefficient of the tubes (kJ/s/m2) A = tube area (m2) D T = temperature difference between HTS and steam generator inventory. A and U are a function of boiler design and therefore Q is proportional to D T.

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If reactor power output increases, then more heat must be transferred to the boiler water. Q has to rise, therefore D T must also increase.

This increase in D T can be achieved by either allowing the average HTS temperature to increase as reactor power increases (as is the case for a pressurize installation) or by arranging that the boiler Pressure falls, and therefore boiler temperature falls, as reactor power increases (as is the case for a Solid HTS designs with no pressurize).

For all units designed with a pressurize, the first method is employed. Whereas for units without Pressurize, the second method is used.

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2-4-1-Boiler pressure control operation for units having a pressurize

Under normal operating conditions, BPC manipulates the reactor power output in order to control boiler pressure to the set point. The turbine/generator, which is the heat sink for the boilers, is controlled to an operator specified set point. "Alternate" or “Reactor Leading” Operation • If the unit is operating in the reactor leading mode - at low power conditions - the reactor power set point is specified by the operator. • Boiler pressure is then controlled to its set point by manipulation of the steam loads, i.e., turbine and steam discharge valves.

Steam Discharge Valve Control

The Atmospheric Steam Discharge Valves (ASDV) and Condenser Steam Discharge Valves (CSDV) are, under normal operating conditions, closed due to the introduction of a bias signal.

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 If, for any reason, the boiler pressure rises above its set point by 70 kPa the ASDVs will open.  If the rise in boiler pressure is greater than 125 kPa above set point the CSDVs will start to open.  If the positive boiler pressure error is not corrected by the ASDVs and CSDVs a reactor setback will be initiated to correct the thermal mismatch (i.e. correct both the demand and the supply).

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2-4-2-Boiler pressure control operation for Units without a Pressurize • Units with only feed and bleed systems for Heat Transport pressure control are normally run as base load, reactor leading, stations. • The response of the Heat Transport System to transients caused by power maneuvering is very limited. • The Boiler Pressure Control System has a role in limiting the potential swell and shrink of the HTS inventory by maintaining the HTS average temperature essentially constant over the full operating range.

To control the boiler pressure, (the controlled variable) the following manipulated variables are used: (a) Reactor Power (b) Turbine Steam Flow (c) Steam Reject Valve (SRV) Steam Flow

• The boiler pressure will be decreased from 5 MPa to 4 MPa as unit power is raised from 0 to 100% full power (this is to minimize HTS temperature changes).

• This is also the turbine operating ramp. The SRV set point is a parallel ramp set 100 kPa higher than the turbine ramp.

• Should the boiler pressure rise by more than 100 kPa excess pressure will be released by the small SRVs.

• If the positive pressure transient is not corrected by the small SRVs the large SRVs will start to open. Opening of the large SRVs will initiate a reactor setback. Boiler Operation And Control

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• If the boiler pressure falls below the turbine set point the speeder gear will run back to a point where the decreased turbine power will be matched.

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2-4-3-Boiler Pressure Response to A Requested Increase in Electrical Output • A request for increased electrical output will create an error signal between the existing output and the new set point. • This error signal will cause the speeder gear to run up and thus increase the steam flow to the turbine. • This increased steam flow will result in an increased electrical output and eliminate the electrical error which had been created. • However, the increased steam flow will inevitably cause boiler pressure to fall. • The increased governor valve opening results in an increased steam pressure on the turbine side of the governor valve. • This pressure increase is used as a feed forward signal which can be used to modify the reactor power set point in advance of the negative boiler pressure error developing. • In practice the feed forward signal will limit the size of the negative boiler pressure transient but is unable to eliminate it completely. • The resulting drop in boiler pressure is used as a feedback signal to the boiler pressure control program. This will cause a further adjustment to be made to reactor power output and thus return the boiler pressure to its set point.

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2-5-Control devices The purpose of the control system is to start, operate, and shut down the combustion process and any related auxiliary processes safely, reliably, and efficiently. A combustion system typically includes a fuel supply, a combustion air supply, and an ignition system, all of which come together at one or more burners. During system start-up and at various times during normal operation, the control system will need to verify or change the status of these systems. During system operation, the control system will need various items of process information to optimize system efficiency. Additionally, the control system monitors all safety parameters at all times and will shut down the combustion system if any of the safety limits are not satisfied.

2-5-1-Control platforms The control platform is the set of devices that monitors and optimizes the process conditions, executes the control logic, and controls the status of the combustion system.

2-5-1-1-Relay System A relay consists of an electromagnetic coil and several attached switch contacts that open or close when the coil is energized or de-energized. A relay system consists of a number of relays wired together in such a way that they execute a logical sequence. For example, a relay system may define a series of steps to start up the combustion process. Relays can tell only if something is on or off and have no analog capability. They are generally located in a local control panel. Advantages of relays Relays have several advantages. They are simple, easily tested, reliable, and wellunderstood devices that can be wired together to make surprisingly complex systems. They are modular, easily replaced, and inexpensive. They can be configured in fail-safe mode so that if the relay itself fails, combustion system safety is not compromised. Disadvantages There are also a few disadvantages of relays. Once a certain complexity level is reached, relay systems can quickly become massive. Although individual relays are Boiler Operation And Control

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very reliable, a large control system with hundreds of relays can be very unreliable. Relays also take up a lot of expensive control panel space. Because relays must be physically rewired to change the operating sequence, system flexibility is poor.

2-5-1-2-Burner Controller A variety of burner controllers is available from several different vendors. They are prepackaged, hardwired devices in different configurations to operate different types of systems. A burner controller will execute a defined sequence and monitor defined safety parameters. They are generally located in a local control panel. Like relays, they generally have no analog capability. Advantages of burner controllers include the fact that they are generally inexpensive, compact, simple to hook up, require no programming, and are fail-safe and very reliable. They are often approved for combustion service by various safety agencies and insurance companies. There are also some disadvantages. Burner controllers cannot control combustion systems of much complexity. System flexibility is nonexistent. If it becomes necessary to change the operating sequence, the controller must be rewired or replaced with a different unit.

2-5-1-3-Programmable Logic Controller (PLC) A programmable logic controller (PLC) is a small, modular computer system that consists of a processing unit and a number of input and output modules that provide the interface to the combustion components. PLCs are usually rack-mounted, and modules can be added or changed. There are many types of modules available. Unlike the relays and burner controllers above, they have analog control capability. They are generally located in a local control panel. PLCs have the advantage of being a mature technology. They have been available for more than 20 years. Simple PLCs are inexpensive and PLC prices are generally very competitive. They are compact, relatively easy to hook up, and, because they are programmable, they are supremely flexible. They can operate systems of almost any complexity level. PLC reliability has improved over the years and is now very good.

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Disadvantages of PLCs include having to write software for the controller. Coding can be complex and creates the possibility of making a programming mistake, which can compromise system safety. The PLC can also freeze up, much like a desktop computer freezes up, where all inputs and outputs are ignored and the system must be reset in order to execute logic again. Because of this possibility, standard PLCs should never be used as a primary safety device. Special types of redundant or fault-tolerant PLCs are available that are more robust and generally accepted for this service, but they are very expensive and generally difficult to implement.

2-5-1-4-Distributed Control System (DCS) A distributed control system (DCS) is a larger computer system that can consist of a number of processing units and a wide variety of input and output interface devices. Unlike the other systems described above, when properly sized, a DCS can also control multiple systems and even entire plants. The DCS is generally located in a remote control room, but peripheral elements can be located almost anywhere. DCSs have been around long enough to be a mature technology and are generally well understood. They are highly flexible and are used for both analog and discrete (on–off ) control. They can operate systems of almost any level of complexity and their reliability is excellent. However, DCSs are often difficult to program. Each DCS vendor has a proprietary system architecture, so the hardware is expensive and the software is often different from any other vendor’s software. Once a commitment is made to a particular DCS vendor, it is extremely difficult to change to a different one.

2-5-1-5-Hybrid Systems If you could combine several of the systems listed above and build a hybrid control system, the advantages of each system could be exploited. In practice, that is what is usually done. A typical system uses relays to perform the safety monitoring, a PLC to do the sequencing, and either dedicated controllers or an existing DCS for the analog Boiler Operation And Control

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systems control. Sometimes, the DCS does both the sequencing and the analog systems control, and the safety monitoring is done by a fault-tolerant logic system. Most approval agencies and insurers require the safety monitoring function to be separate from either of the other functions.

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When we control burners of boilers, we keep 2 bounds in our consideration; 1- If the amount of fuel burned is more than required duty, overheating will occur. 2- If the omount of fuel burned is less than required, drop in power will happen. If we connect the boiler to turbine, it will make the turbine work in wet region.

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2-5-2-Analog devices 2-5-2-1-Control Valves Control valves are among the most complex and expensive components in any combustion control system. As shown in Figure, the type of service and control desired determines the selection of different flow characteristics and valve sizes. Controls engineers use a series of calculations to help with this selection process. A typical control valve consists of several components that are mated together before installation in the piping system: a) Control Valve Body The control valve body can be a globe valve, a butterfly valve, or any other type of adjustable control valve. Usually, special globe valves of the equal percent type are used for fuel gas control service or liquid service. Control of combustion air and waste gas flows generally require the use of butterfly valves — often the quick-opening type. Because the combustion air or waste line usually has a large diameter, and the cost of globe valves quickly becomes astronomical after the line size exceeds 3 or 4 inches, butterfly valves are usually the most economical choice.

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b) Actuator The actuator supplies the mechanical force to position the valve for the desired flow rate. For control applications, a diaphragm actuator is preferred because, compared to a piston-type actuator, it has a relatively large pressure-sensitive area and a relatively small frictional area where the stem is touching the packing. This ensures smooth operation, precision, and good repeatability. Proper selection of the actuator must take into account valve size, air pressure, desired failure mode, process pressure, and other factors. Actuators are usually spring-loaded and single-acting, with control air used on one side of the diaphragm and the spring on the other. The air pressure forces the actuator to move against the spring. If air pressure is lost, the valve fails to the spring position thus, the actuator is chosen carefully to fail to a safe position (i.e., closed for fuel valves, open for combustion air valves). c) Current-to-Pressure Transducer The current-to-pressure transducer, usually called the I/P converter, takes the 24 VDC (4 to 20 milliamps) signal from the controller and converts it into a pneumatic signal. The signal causes the diaphragm of the actuator to move to properly position the control valve. d) Positioner The positioner is a mechanical feedback device that senses the actual position of the valve as well as the desired position of the valve. It makes small adjustments to the pneumatic output to the actuator to ensure that the desired and the actual position are the same. e) Three-Way Solenoid Valve When energized, the three-way solenoid valve admits air to the actuator. When deenergized, it dumps the air from the actuator. Because single-acting actuators are generally used, the spring in the actuator forces the valve either fully open or fully closed, depending on the engineer’s choice of failure modes when specifying the valve. Obviously, a control valve that supplies fuel gas to a combustion system should Boiler Operation And Control

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fail closed, while the control valve that supplies combustion air to the same system should fail open. f) Mechanical Stops Mechanical stops are used to limit how far open or shut a control valve can travel. If it is vital that no more than a certain amount of fluid ever enters a downstream system, an “up” stop is set. If it is necessary to ensure a certain minimum flow, for cooling purposes for example, a “down” stop is set. In the case of a fuel supply control valve, the “down” stop is set so that during system lightoff, an amount of fuel ideal for smooth and reliable burner lighting is supplied. After a defined settling interval, usually 10 seconds, the three-way solenoid valve is energized and normal control valve operation is enabled.

2-5-2-2-Thermocouples Whenever two dissimilar metals come into contact, current flows between the metals and the magnitude of that current flow and the voltage driving it, vary with temperature. This phenomenon is called the Seebeck effect. If both of the metals are carefully chosen and are of certain known alloy compositions, the voltage will vary in a nearly linear manner with temperature over some known temperature range. Because the temperature and voltage ranges vary depending on the materials employed, engineers use different types of thermocouples for different situations. In combustion applications, the “K” type thermocouple (0 to 2400°F or−18 to 1300°C) is usually used. When connecting a thermocouple to a transmitter, the transmitter should be set up for the type of thermocouple employed. Installing thermocouples in a protective sheath known as a thermowell prevents the sensing element from suffering the corrosive or erosive effects of the process being measured. However, a thermowell also slows the response of the instrument to changing temperature and should be used with care.

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Figure 1 thermo couple

2-5-2-3-Velocity Thermocouples Also known as suction pyrometers, the design of velocity thermocouples attempts to minimize the inaccuracies in temperature measurement caused by radiant heat. Inside a combustor, the thermocouple measures the gas temperature. However, the large amount of heat radiated from the hot surroundings significantly affects the measurement. A velocity thermocouple shields the thermocouple from radiant heat by placing it in one or more concentric hollow pipes. Hot gas is induced to flow across the thermocouple, producing a gas temperature reading without a radiant component.

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2-5-2-4-Resistance Temperature Detectors (RTDs)

Resistance of any conductor increases with temperature. For a specific material of known resistance, it is possible to infer the temperature. Similar to the thermocouples described above, the linearity of the result depends on the materials chosen for the detector and their alloy composition. Engineers sometimes use RTDs instead of thermocouples when higher precision is desired. Platinum is a popular material for RTDs because it has good linearity over a wide temperature range. Like thermocouples, installation of RTDs in thermowells is common.

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2-5-2-5-Pressure Transmitters A pressure transmitter is usually used to provide an analog pressure signal. These devices use a diaphragm coupled to a variable resistance, which modifies the 24 VDC loop current (4 to 20 milliamps) in proportion to the range in which it is calibrated. In recent years, these devices have become enormously more accurate and sophisticated, with onboard intelligence and self calibration capabilities. They are available in a wide variety of configurations and materials and can be used in almost any service. It is possible to check and reconfigure these “smart” pressure transmitters remotely with the use of a handheld communicator.

2-5-2-6-Flow Meters There are many different types of flow meters and many reasons to use one or another for a given application. The following is a list of several of the more common types of flow meters, how they work, and where they are used.

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2-5-2-6-1-Vortex Shedder Flow Meter A vortex shedder places a bar in the path of the fluid. As the fluid goes by, vortexes (whirlpools) form and break off constantly. An observation of the water swirling on the downstream side of bridge pilings in a moving stream reveals this effect. Each time a vortex breaks away from the bar, it causes a small vibration in the bar. The frequency of the vibration is proportional to the flow.

Vortex shedders have a wide range, are highly accurate, reasonably priced, highly reliable, and useful in liquid, steam, or gas service.

2-5-2-6-2-Magnetic Flow Meter A magnetic field, a current carrying conductor, and relative motion between the both creates an electrical generator.

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In the case of a magnetic flow meter, the meter generates the magnetic field and the flowing liquid supplies the motion and the conductor. The voltage produced is proportional to the flow. These meters are highly accurate, very reliable, have a wide range, but are somewhat expensive. They are useful with highly corrosive or even gummy fluids as long as the fluids are conductive. Only liquid flow is measured.

2-5-2-6-3-Orifice Flow Meter Historically, almost all flows were measured using this method and it is still quite popular. Placing the orifice in the fluid flow causes a pressure drop across the orifice. A pressure transmitter mounted across the orifice calculates the flow from the amount of the pressure drop. Orifice meters are very accurate but have a narrow range. They are reasonably priced, highly reliable, and are useful in liquid, steam, or gas service.

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2-5-2-6-4-Coriolis Flow Meter

The Coriolis flow meter is easily the most complex type of meter to understand. The fluid runs through a U-shaped tube that is being vibrated by an attached transducer. The flow of the fluid will cause the tube to try to twist because of the Coriolis force. The magnitude of the twisting force is proportional to flow. These meters are highly accurate and have a wide range. They are generally more expensive than some other types.

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2-5-2-6-5-Ultrasonic Flow Meter When waves travel in a medium (fluid), their frequency shifts if the medium is in motion relative to the wave source.

The magnitude of the shift, called the Doppler effect, is proportional to the relative velocity of the source and the medium. The ultrasonic meter generates ultrasonic Boiler Operation And Control

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sound waves, sends them diagonally across the pipe, and computes the amount of frequency shift. These meters are reasonably accurate, have a fairly wide range, are reasonably priced, and are highly reliable. Ultrasonic meters work best when there are bubbles or particulates in the fluid.

2-5-2-6-6-Turbine Flow Meters

A turbine meter is a wheel that is spun by the flow of fluid past the blades. A magnetic pickup senses the speed of the rotation, which is proportional to the flow. These meters can be very accurate but have a fairly narrow range. They must be very carefully selected and sized for specific applications. They are reasonably priced and fairly reliable. They are used in liquid, steam, or gas service.

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2-5-2-6-7-Positive Displacement Flow Meters

Positive displacement flow meters generally consist of a set of meshed gears or lobes that are closely machined and matched to each other. When fluid is forced through the gears, a fixed amount of the fluid is allowed past for each revolution. Counting the revolutions reveals the exact amount of flow. These meters are extremely accurate and have a wide range. Because there are moving parts, the meters must be maintained or they can break down or jam. They also cause a large pressure drop, which can be important for certain applications.

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