AUTOMATIC BOILER CONTROL SYSTEMGROUP MEMBER : PUVENTHIRAN A/L SUBRAMANIAM PIC 097086

KAMIL BIN MAT ISA PIC 097024

MEGAT NOR AZMEER BIN MEGAT RAMLI PIC 097028 MOHAMAD KHIDIR BIN ABDUL AZIZ PIC 087021

CLASS : SEM 4 PIC 3TTO : MS ALYSTER WONG

P R O C E S S I N D U S T R I

A L

C O N T R O L

INTRODUCTION

Contemporary supercritical steam generators are sometimes referred as Benson boilers. In 1922, Mark Benson was granted a patent for a boiler designed to convert water into steam at high pressure. Safety was the main concern behind Benson’s concept. Earlier steam generators were designed for relatively low pressures of up to about 100 bar (10,000 kPa; 1,450 psi), corresponding to the state of the art in steam turbine development at the time. One of their distinguishing technical characteristics was the riveted water/steam separator drum. These drums were where the water filled tubes were terminated after having passed through the boiler furnace. These header drums were intended to be partially filled with water and above the water there was a baffle filled space where the boiler's steam and water vapor collected. The entrained water droplets were collected by the baffles and returned to the water pan. The mostly dry steam was piped out of the drum as the separated steam output of the boiler. These drums were often the source of boiler explosions, usually with catastrophic consequences. However, this drum could be completely eliminated if the evaporation separation process was avoided altogether. This would happen if water entered the boiler at a pressure above the critical pressure (3,206 psi); was heated to a temperature above the critical temperature (706 degrees F) and then expanded (through a simple nozzle) to dry steam at some lower subcritical pressure. This could be obtained at a throttle valve located downstream of the evaporator section of the boiler. As development of Benson technology continued, boiler design soon moved away from the original concept introduced by Mark Benson. In 1929, a test boiler that had been built in 1927 began operating in the thermal power plant at Gartenfeld in Berlin for the first time in subcritical mode with a fully open throttle valve. The second Benson boiler began operation in 1930 without a pressurizing valve at pressures between 40 and 180 bar (4,000 and 18,000 kPa; 580 and 2,611 psi) at the Berlin cable factory. This application represented the birth of the modern variable-pressure Benson boiler. After that development, the original patent was no longer used. The Benson boiler name, however, was retained. Two current innovations have a good chance of winning acceptance in the competitive market for once-through steam generators: A new type of heat-recovery steam generator based on the Benson boiler, which has operated successfully at the Cottam combined-cycle power plant in the central part of England, The vertical tubing in the combustion chamber walls of coal-fired steam generators which combines the operating advantages of the Benson system with the design advantages of the drum-type boiler. Construction of a first reference plant, the Yaomeng power plant in China, commenced in 2001.

OBJECTIVE

Automatic boiler control system consists of temperature, level and combustion process to make it function well. There are several objectives of doing the automatic boiler control system assignment

To measure and control the level of water

To measure and control the temperature of the steam

To know the combustion process needed for boiler system

To know how to use the P & ID

To learn about the industrial process in detail

From the all objective above , we can conclude that automatic boiler control system

helps us to understand the process and make us realize that it is not make up of only

one process but many that are as temperature, level and combustion process.

Types of boiler system

Superheated Steam Boiler

Most boilers produce steam to be used at saturation temperature; that is, saturated steam. Superheated steam boilers vaporize the water and then further heat the steam in a superheater. This provides steam at much higher temperature, but can decrease the overall thermal efficiency of the steam generating plant because the higher steam temperature requires a higher flue gas exhaust temperature. There are several ways to circumvent this problem, typically by providing an economizer that heats the feed water, a combustion air heater in the hot flue gas exhaust path, or both. There are advantages to superheated steam that may, and often will, increase overall efficiency of both steam generation and its utilisation: gains in input temperature to a turbine should outweigh any cost in additional boiler complication and expense. There may also be practical limitations in using wet steam, as entrained condensation droplets will damage turbine blades. Superheated steam presents unique safety concerns because, if any system component fails and allows steam to escape, the high pressure and temperature can cause serious, instantaneous harm to anyone in its path. Since the escaping steam will initially be completely superheated vapor, detection can be difficult, although the intense heat and sound from such a leak clearly indicates its presence. Superheater operation is similar to that of the coils on an air conditioning unit, although for a different purpose. The steam piping is directed through the flue gas path in the boiler furnace. The temperature in this area is typically between 1,300–1,600 degrees Celsius (2,372–2,912 °F). Some superheaters are radiant type; that is, they absorb heat by radiation. Others are convection type, absorbing heat from a fluid. Some are a combination of the two types. Through either method, the extreme heat in the flue gas path will also heat the superheater steam piping and the steam within. While the temperature of the steam in the superheater rises, the pressure of the steam does not: the turbine or moving pistons offer a continuously expanding space and the pressure remains the same as that of the boiler. Almost all steam superheater system designs remove droplets entrained in the steam to prevent damage to the turbine blading and associated piping.

A superheated boiler on a steam locomotive

Supercritical Steam Generators

Supercritical steam generators (also known as Benson boilers) are frequently used for the production of electric power. They operate at supercritical pressure. In contrast to a subcritical boiler, a supercritical steam generator operates at such a high pressure (over 3,200 psi/22.06 MPa or 220.6 bar) that actual boiling ceases to occur, and the boiler has no water - steam separation. There is no generation of steam bubbles within the water, because the pressure is above the critical pressure at which steam bubbles can form. It passes below the critical point as it does work in the high pressure turbine and enters the generator's condenser. This is more efficient, resulting in slightly less fuel use.

Hydronic boilers

Hydronic boilers are used in generating heat for residential and industrial purposes. They are the typical power plant for central heating systems fitted to houses in northern Europe (where they are commonly combined with domestic water heating), as opposed to the forced-air furnaces or wood burning stoves more common in North America. The hydronic boiler operates by way of heating water/fluid to a preset temperature (or sometimes in the case of single pipe systems, until it boils and turns to steam) and circulating that fluid throughout the home typically by way of radiators, baseboard heaters or through the floors. The fluid can be heated by any means...gas, wood, fuel oil, etc., but in built-up areas where piped gas is available, natural gas is currently the most economical and therefore the usual choice. The fluid is in an enclosed system and circulated throughout by means of a motorized pump. The name "boiler" can be a misnomer in that, except for systems using steam radiators, the water in a properly functioning hydronic boiler never actually boils. Most new systems are fitted with condensing boilers for greater efficiency. These boilers are referred to as condensing boilers because they condense the water vapor in the flue gases to capture the latent heat of vaporization of the water produced during combustion. Hydronic systems are being used more and more in new construction in North America for several reasons. One of the reasons is they are more efficient and more economical than forced-air systems (although initial installation can be more expensive, because of the cost of the copper and aluminum).

PID CONTROLLER

A proportional–integral–derivative controller (PID controller) is a generic control loop feedback mechanism (controller) widely used in industrial control systems – a PID is the most commonly used feedback controller. A PID controller calculates an "error" value as the difference between a measured process variable and a desired set point. The controller attempts to minimize the error by adjusting the process control inputs. The PID controller calculation (algorithm) involves three separate constant parameters, and is accordingly sometimes called three-term control: the proportional, the integral and derivative values, denoted P, I, and D. Heuristically, these values can be interpreted in terms of time: P depends on the present error, I on the accumulation of past errors, and D is a prediction of future errors, based on current rate of change. The weighted sum of these three actions is used to adjust the process via a control element such as the position of a control valve or the power supply of a heating element. In the absence of knowledge of the underlying process, a PID controller is the best controller. By tuning the three parameters in the PID controller algorithm, the controller can provide control action designed for specific process requirements. The response of the controller can be described in terms of the responsiveness of the controller to an error, the degree to which the controller overshoots the setpoint and the degree of system oscillation. Note that the use of the PID algorithm for control does not guarantee optimal control of the system or system stability. Some applications may require using only one or two actions to provide the appropriate system control. This is achieved by setting the other parameters to zero. A PID controller will be called a PI, PD, P or I controller in the absence of the respective control actions. PI controllers are fairly common, since derivative action is sensitive to measurement noise, whereas the absence of an integral term may prevent the system from reaching its target value due to the control action.

DESCRIPTOON OF SYSTEM

P&ID DIAGRAM OF SUPERHEATED BOILER SYSTEM

P&ID CONTROL STRATEGY DESIGN

Level

Level of the feed water in boiler is detected by the level transmitter. Then the comparator receives signal from the level transmitter and compare the output (rate of steam production) with input . Now the level controller receives the signal from the comparator and do some calculation according to the PID algorithms. Finally, the final control element receives the manipulated variable (Y) from the controller and operates according to the signal. If the value of error is not zero the valve either opens or close according to the controller signal to make the value of output is equal to the input.

PID LEVEL LOOP CONNECTION DIAGRAM

Control

LawFCE

Level Process

LT

e xy

LEVEL CONTROLLER

Temperature

Temperature of the steam in boiler is detected by the temperature transmitter. Then the comparator receives signal from the temperature transmitter and compare the output (rate of steam production) with input . Now the temperature controller receives the signal from the comparator and do some calculation according to the PID algorithms. Finally, the final control element receives the manipulated variable (Y) from the controller and operates according to the signal. If the value of error is not zero the valve either opens or close according to the controller signal to make the value of output is equal to the input.

PID TEMPERATURE LOOP CONNECTION DIAGRAM

Control

LawFCE

Temperature

Process

TT

e xy

TEMPERATURE CONTROLLER

COMBUSTION

It consists of two flow controller and two flow transmitter. One is for the fuel and another is for air. Both air and fuel are needed for the combustion process take place. The air control valve and fuel control valve is at the field while the flow controller 1 and flow controller 2 is at the panel. The back panel consists of the distributor which link the two controllers, the two transmitters and the two control valves. The controller is not place at the field as we can use programmable logic controller or another device to control the system from the control panel.

DISADVANTAGES

Feed water line Erosion

High-velocity water and especially water or steam mixtures cause erosion in feed water systems. The most commonly encountered erosion problems occur at the hairpin bends in steaming economizers. Here, the mixture of steam and water thins the elbows, leaving a characteristic reverse horseshoe imprint. Similar problems can be encountered in feedwater lines where high velocities create the familiar thinning pattern. These problems can occur even at moderate average flow velocities when a sequence of bends causes a significant increase in local velocity. In order to mitigate erosion problems, it is helpful to maintain water chemistry conditions that form the most tenacious oxide layer. However, the problems cannot be completely resolved without design or operational changes.

Failure due to Overheating

When tube failures occur due to overheating and plastic flow (conditions commonly associated with deposits), the cause is usually identified by the deposits which remain, An accurate analysis of the deposits indicates the source of the problem and the steps needed for correction. Metallographic analyses are useful, at times, in confirming whether a short- or long-term exposure to overheating conditions existed prior to failure. Such analyses are helpful also when metal quality or manufacturing defects are

suspected, although these factors are significant only in isolated instances. When tube failures occur due to overheating, a careful examination of the failed tube section reveals whether the failure is due to rapid escalation in tube wall temperature or a long-term, gradual build-up of deposit. When conditions cause a rapid elevation in metal temperature to 1600°F or above, plastic flow conditions are reached and a violent rupture occurs. Violent bursts of the thin-lipped variety occur when water circulation in the tube is interrupted by blockage or by circulation failure caused by low water levels. In some steam drum designs, water level is extremely critical because the baffling may isolate a generating section of the boiler when the steam drum water level falls below a certain point. Thin-lipped bursts also occur in super heater tubes when steam flow is insufficient, when deposits restrict flow, or when tubes are blocked by water due to a rapid firing rate during boiler start-up. Interruptions in flow do not always result in rapid failure. Depending on the metal temperature reached, the tube can be damaged by corrosive or thinning mechanisms over a long period of time before bulges or blisters or outright failures develop. In such instances, a metallurgical examination in addition to an examination of the contributing mechanical factors can be helpful in identifying the source of the problem. A long-term scaling condition which will lead to a tube leak is usually indicated by a wrinkled, bulged external surface and a final thick-lipped fissure or opening. This appearance is indicative of long-term creep failure created by repetitive scale formation, causing overheating and swelling of the tube surface in the form of a bulge or blister. The scale, in such instances, tends to crack off; water contacts the metal and cools it until further scaling repeats the process. The iron oxide coating on the external surface cracks during the process, giving rise to the characteristic longitudinal creep cracks.

Fatigue and Corrosion Fatigue

Trans granular cracking primarily due to cyclic stress is the most common form of cracking encountered in industrial boilers. In order to determine the cause of a Trans granular failure, it is necessary to study both the design and the operating conditions of the boiler. Straight tube, shell-and-tube waste heat boilers frequently develop tube and tube sheet failures due to the imposition of unequal stresses. A primary cause of this is the uneven distribution of hot gases across the face of the tube sheet. The tubes involved tend to come loose, creating leakage problems. Even when the tubes are securely welded, imposed stresses can cause transverse cracking of the tubes. Any design feature that allows steam pockets to form within a unit can cause cyclic overheating and quenching. This can lead to transverse cracking of tubes and, occasionally, shells. Such cracking always appears in the area of greatest stress and results in cracks that are primarily Trans granular. Some inter crystalline cracking may develop in this type of failure whether or not free Na OH is present. However, the predominant type of cracking is across the grain structure of the metal. Because it is mechanically induced, the cracking occurs irrespective of boiler water chemical concentrations. The cracks are often accompanied by a number of pits adjacent to or in

line with the cracking- another specific indicator of the mechanical stresses imposed. Any corrosives present contribute to the formation of the pits. The normal reaction between iron and water is sufficient to cause pitting at breaks in the thin oxide film formed on freshly exposed surfaces under stress.

Stress-Induced Corrosion

Certain portions of the boiler can be very susceptible to corrosion as a result of stress from mechanical forces applied during the manufacturing and fabrication processes. Damage is commonly visible in stressed components, such as rolled tube ends, threaded bolts, and cyclone separators. However, corrosion can also occur at weld attachments throughout the boiler (see Figure 14-5) and can remain undetected until failure occurs. Regular inspection for evidence of corrosion, particularly in the wind box area of Kraft recovery boilers, is recommended because of the potential for an explosion caused by a tube leak. The potential for stress-induced corrosion can be reduced if the following factors are minimized: stresses developed in the boiler components, the number of thermal cycles, and the number of boiler chemical cleanings. In addition, it is necessary to maintain proper water chemistry control during operation and to provide protection from corrosion during shutdowns.

Dissolved Oxygen

Dissolved oxygen corrosion is a constant threat to feed water heater, economizer, and boiler tube integrity. As deposit control treatment methods have improved, the need for effective control of oxygen has become increasingly important. The first serious emphasis on oxygen control began when phosphate-based treatments were introduced

to replace the soda ash treatments common before that time. The dense, hard calcium carbonate scale which developed with the soda ash treatments protected tubes and drums from serious oxygen corrosion. With the application of phosphate treatment, the tube and drum surfaces were cleaner. Therefore, more of the surface area was exposed to corrosives in the water. This spurred the use of improved open feed water heaters to remove most of the oxygen prior to the entrance of water into the boiler. Today, most plants are equipped with efficiently operated deaerating heaters. The use of oxygen scavengers, such as catalysed sodium sulphite hydrazine, and organic scavengers, is also standard practice. The use of chelant treatments and demineralized water has improved the cleanliness of boiler heat transfer surfaces to such an extent that essentially bare-metal conditions are common. Only a thin, protective, magnetic oxide film remains in such instances. As a result, oxygen control has become even more essential today. The use of catalysed sulphite, where applicable, is a standard recommendation in chelant applications. The control of downtime corrosion has become increasingly important in recent years to prevent or inhibit pitting failures. Often, cold water that has not been deaerated is used for rapid cooling or start-up of a boiler. This is a risky operating practice, usually chosen for economic reasons. Severe pitting can occur in such instances, especially in boilers that have been maintained in a deposit-free condition. Therefore, it is usually more economical to maintain clean heat transfer surfaces and eliminate the use of cold water containing dissolved oxygen during cool-down and start-up periods. This practice can result in fuel savings and improved boiler reliability.

Acidic Attack

Acid attack of boiler tubes and drums is usually in the form of general thinning of all surfaces. This results in a visually irregular surface appearance. Smooth surfaces appear at areas of flow where the attack has been intensified. In severe occurrences, other components, such as baffling, nuts and bolts, and other stressed areas, may be badly damaged or destroyed, leaving no doubt as to the source of the problem. Severe instances of acid attack can usually be traced to either an unsatisfactory acid cleaning operation or process contamination. Some industrial plants encounter periodic returned condensate contamination, which eliminates boiler water alkalinity. Occasionally, regeneration acid from an ion exchange process is discharged accidentally into the boiler feed water system. Cooling water contamination of condensate can depress boiler water pH and cause severe deposition and pitting in areas of high heat flux. Damage can be quite severe if immediate steps are not taken to neutralize the acid. In the case of industrial process contamination, it is possible for organic contaminants to decompose under boiler temperature and pressure to form organic acids. Sugar is an excellent example of an organic which, when returned in a large quantity, can cause rapid loss of boiler water alkalinity and reduce pH of the boiler water to 4.3 and lower. Most sugar refining plants maintain standby pumping systems, to add caustic soda to neutralize these acids as quickly as possible.

CONCLUSION

We are able to measure and control the level of water and we are able to measure and control the temperature of the steam. We also can control the combustion ratio so that we can produce steam at desired rate. Based from the level , temperature and combustion , we can see that level use P&I controller for eliminating error and stabilization of the boiler system. Combustion also took the same operation. However, temperature use P&ID controller to make the reaction time to become faster.

REFERENCES

http://en.wikipedia.org/wiki/Boiler

http://www.muswell-hill.com/foxandco/pages/boilertypes.htm

http://www.gewater.com/handbook/boiler_water_systems/ch_14_systemfailure.jsp