Holding its exact and masses praised association, this top textual content has been revised to mirror the newest advancements in layout instruments. It presents balanced assurance of suitable basics and real-world practices in order that scholars, apprentices and on-the-job execs can comprehend the real and infrequently complicated interrelationships among die layout and the commercial elements all in favour of production sheet-metal forming items.
The electronic Divide refers back to the perceived hole among those that have entry to the newest info applied sciences and those that don't. If we're certainly in a data Age, then now not gaining access to this knowledge is an financial and social handicap. The energy balance of the boiler is shown in Figure Energy enters and leaves a boiler in a variety of ways.
Energy in the steam is the only output considered useful. Fuel energy is by far the major energy input and, unless precise efficiency values are needed, is normally the only energy input considered.
The percentage of hydrogren and moisture in the fuel affects this loss. Although blowdown is not a useful heat output from the viewpoint of boiler efficiency, it is not considered a loss because the boiler has properly transferred the heat from the fuel to the water. This edition doesn't have a description yet. Can you add one? Add another edition?
Copy and paste this code into your Wikipedia page. Need help? The control of boilers Sam G. Donate this book to the Internet Archive library. If you own this book, you can mail it to our address below. Want to Read. Check nearby libraries Library. Share this book Facebook. Last edited by ImportBot. December 24, History. An edition of The control of boilers The ignition temperature and also the flame temperature are different for different fuels if all other conditions are the same. Of these, when properly mixed with air, the gases have the highest temperature required for ignition.
Various liquid fuels if properly atomized and mixed with air have the lowest ignition temperatures. The table of flammable mixture limits identifies that coal may continue burning or be ignited with as little as 8 percent of the theoretical air required for combustion.
This can also occur if the gases are chilled by heat being withdrawn before the combustion proceeds to completion. The chilling may occur if the flame impinges on relatively cold boiler heat transfer surfaces in the furnace. It can also occur if the furnace volume is too low and allows too little time for complete combustion to take place before the gases are chilled by the convection heating surfaces of the boiler. Figure dem- onstrates some of these effects as they relate to the products of combustion.
The nitrogen from the air and any other non-combustibles in the fuel pass through the process with essentially no chemical change. A minimal amount of nitrogen in the air combines with oxygen to form nitrous oxides NOx , which pollute the air.
Some fuels contain a small percentage of sulphur, which-when burned-results in sulphur oxides that pollute the air. These may also corrode the boiler if the flue gas containing them is allowed to cool below the dew point. Figure demonstrates the basic chemical process and the chemical elements and com- pounds involved in complete and incomplete combustion. For any fuel, a precise amount of. IuI Aldehydes.
Other Combustible. The precise amount of combustion air is called thc theoretical air for that particular fuel. If the fuel analysis is known, the theoretical air requirements can be calculated easily.
The amounts of carbon and oxygen for complete combustion of carbon are represented by the formula:. Weights equivalent to the molecular weight in pounds combine. One molecule of carbon containing one atom of carbon combines with one molecule of oxygen containing two atoms of oxygen to form one molecule of carbon dioxide containing one atom of carbon and two atoms of oxygen.
The formula for the combustion of hydrogen is represented:. As with the carbon combustion, weights equivalent to the molecular weights in pounds combine. Two molecules of hydrogen, each containing two atoms of hydrogen, and one mol- ecule of two atoms of oxygen make two molecules of water, with a total of four atoms of hydrogen and two atoms of oxygen.
A simple example of the many incomplete combustion reactions resulting in intermediate hydrocarbon compounds is the partial combustion of carbon, resulting in carbon monoxide rather than carbon dioxide. In this case some of the potential heat energy from the carbon remains in the carbon monoxide. With the right conditions of time, temperature, and turbulence, and by adding more oxygen to the carbon monoxide, the carbon monoxide will further oxidize to carbon dioxide, releasing the second part of the heat energy from the original carbon.
The common chemical reactions in combustion are shown in Table , with the heat energy resulting from the combustion reaction. Figures and 5- 10 and Table identify those products of combustion that are produced by the oxidation of the hydrogen, carbon, or sulfur present in the fuel. As indicated, the combustion process produces heat, but a low percentage of the heat produced is not useful in transferring heat to the boiler water.
As hydrogen combines with oxygen during the combus-. This vaporization absorbs the latent heat for producing the steam from the hot com- bustion gases. As the gases pass through the boiler and exit from the system, the gases retain the vaporized water in the form of superheated steam, and the latent heat and any remaining sensible heat are lost from the process.
The amount of latent heat loss is determined by the hydrogen content of the fuel. The effect on boiler efficiency for different fuels is shown in Figure 5- 1 1. All water vapor discharged in flue gas. Actually, value changes with fuel analy- sis due to change in partial pressure of H,O in the flue gases.
It is important to keep in mind that combustion air must be furnished for the total combustion or on the basis of the HHV, while only the LHV has any effect on the heat transfer of the system. Figure demonstrates with a coal analysis how the difference between these two heating values can be calculated.
The amount of oxygen can easily be converted to a quantity of combustion air due to the known content of oxygen in air. An example of this calculation using a formula developed from the combustion equations and the known content of oxygen in air is given in Figure In this example the amount of air theoretically re- quired to produce 10, Btu is also shown.
Table is a tabulation of combustion constants. B Theoretical Air Example. Substance Formula Weight cu ft Ib 1. Paraffin series 7 Methane Hg dry. Figure demonstrates using the table of combustion constants for a gaseous fuel of 85 percent methane and 15 percent ethane. Note that the amount of combustion air required to produce 10, Btu is nearly the same for coal and natural gas.
The fact that combustion air requirements can be closely approximated, based on the heat requirement, is an important concept used in the application of combustion control logic. Additionally, cqmplete mixing may take too much time-so that the gases pass to a lower temperature area not hot enough to complete the combustion-before the process is completed. If only the amount of theoretical air were furnished, some fuel would not burn, the com- bustion would be incomplete, and the heat in the unburned fuel would be lost.
To assurc complete combustion, additional combustion air is furnished so that every molecule of the fuel can easily find the proper number of oxygen molecules to complete the combustion. This additional amount of combustion air that is furnished to complete the combustion process is called excess air.
Excess air plus theoretical air is called total air. The oxygen portion of the flue gas can be used to determine the percentage of excess air.
If the percentage of excess air is increased, flame temperature is reduced and the boiler heat transfer rate is reduced. The usual effect of this change is the increase in the flue gas temperature, as shown in Figure If oxygen in the flue gas is known or can be measured and no table or curve is available, the following empirical formula provides a close approximation of the percentage of excess air.
Measurements of either percentage of carbon dioxide or the percentage of oxygen in the flue gas or both are used to determine percentage of excess air, but the percentage of oxygen is preferred for the following reasons: 1 Oxygen is part of the air-if oxygen is zero, then excess air is zero. The presence of oxygen always indicates that some percentage of excess air is present.
It is thus possible, with the same percentage of carbon dioxide, to have two different percentages of total combustion air. For this reason, the per-. The heat loss in the flue gases essentially depends upon the difference between the tem- perature of the flue gases and that of the incoming combustion air, the amount of excess air, and the fuel analysis.
There is an optimum amount of excess air because less air will mean unburned fuel from incomplete combustion, and more air will mean complete combustion but more heat loss in the flue gas due to the greater mass of the flue gases. The amount of excess air required depends upon the type of fuel, burner design, fuel characteristics and preparation, furnace design, capacity as a percent of maximum, and other factors.
The amount for any installation should be determined by testing that particular unit. An approximate amount of excess air required for full capacity is shown in Table The charts in Figures , , and show the relationship between the flue gas analysis by volume and the percentage of excess air for natural gas, fuel oil, and coal.
These curves also show the difference between the flue gas analysis depending upon the presence or removal of the water vapor that is formed by the combustion process. This differ- ence is important to note for two reasons. If combustible gases such as CO are present, the high temperature and catalytic action of the measuring cell complete the combustion by subtracting a portion or all of the oxygen passing the analysis cell.
Since these formulas are on the dry basis, however, it is necessary to convert the wet basis analyzer readings to dry basis before using them in the older equations for combustion calculations. Line 2 shows HIC ratio by weight of fuel. Line 2 shows excess air in sample as tested.
Figure , which is based on dry basis analysis, can be used for this purpose. If it is not, the fuel has changed or the results of the analysis are incorrect. If boiler tests are being made and the fuel analysis is constant, any data within limits of mea- surement accuracy that doesn't measure up to this kind of examination should be thrown out. Section 6 Efficiency Calculations.
Two different methods are used for calculating the efficiency of boilers. Both of these methods are useful, but it is generally agreed that the heat loss method provides more accurate results. This formula is based on a knowledge of the flows of steam from the boiler, feedwater to the boiler, blowdown from the boiler, and fuel to the boiler.
In addition, the unit heating value of each of these flows must be known. All the flows above can be determined from flowmeters. If steam flow alone or feedwater flow alone is known, blowdown flow can often be determined from the chemical relationships between feedwater entering the boiler and the water in the boiler.
The heat content of the fuel must be determined by the use of a fuel calorimeter. For liquid or solid fuels such as oil or coal, a laboratory test is necessary. In the formula shown in Figure , the output of the boiler is credited with all the heat that is added to the incoming feedwater. This heat added includes the non-useful heat added to the blowdown flow in increasing its temperature from feedwater temperature to the satu- ration temperature of the boiler water.
At least three flows are used in this calculation method. The potential for erroneous results because of flowmeter inaccuracy is the primary weak- ness of this calculation method. In addition to flowmeter inaccuracy, more inaccuracies can be introduced in the determination of the heat content of the fuel. It is also normal that a steam, water, or fuel flowmeter may not be operating under its design condition of pressure, temperature, specific gravity, etc.
Unless particular care is taken in correcting the flowmeter results to design conditions, further inaccuracies can easily be introduced. With gas flowmeters, the basic design conditions of the meter may not match the conditions of the calorimeter.
Particular care must be taken to see that the heating value and fuel flow are on the same basis. Note that completion of this worksheet forces correction to design conditions for the flow- meters and calorimetric determination.
The three formulas shown are based on different com- binations of flowmeter results and the particular flowmeters that are available. The usefulness of this calculation method is derived from its ease of understanding and its ease of calculation.
Though precise results may not be attainable, inaccuracies will probably repeat closely from day to day. This method is therefore useful in tracking daily performance.
Steam Flow, Ibs - Design B. Pressure, psig C. Temperature, OF D. Corrected Steam Flow, Ibs E. Feedwater Flow, Ibs - Design G.
Feedwater Temperature, OF H. Corrected Feedwater Flow, Ibs I. Blowdown Flow, Ibs' - Design K. Blowdown Temperature, OF L. Corrected Blowdown Flow, Ibs M. Enthalpy of Blowdown, Btuflb N. Gas Flow, scf at std. Gas Pressure, psig P. Gas Temperature, OF Q. Corrected Gas Flow, scf at std. Heat Content of Gas at std. The individual losses are identified in Figure Figure also identifies the method of determining the losses.
In this method, a particular fuel unit, 1 mole or moles, 1 lb or Ibs of fuel, is used. For the fuel unit the mass of the flue gases is determined. The sensible heat losses are determined by multiplying the flue gas mass flows by the mean specific heat MCJ between the flue gas temperature and the combustion air inlet temperature.
The result is then multiplied by the difference in temperature between the flue gases and the combustion air. Each loss is calculated in terms of heat units Btu, for example , the heat units totalized, and the percentage of the heating value of the total fuel unit determined. Almost identical results can be obtained from either method if the calcu- lations are carefully made. If impmcticol to waigh refuse, this X [ ' ' ,' ' ' '. Fuel Unlt N2 H20 ,.
H20 - Air - 8. Note that in the formula in line no. If a precisely calculated specific heat value is used instead of the standard 0. For precise results both meth- ods require knowledge of the fuel analysis and the flue gas analysis. This worksheet has been completed for a specific analysis by weight of a particular fuel oil but can be used for any fuel for which the analysis by weight is known.
In column 1 the percentage by weight for the fuel components is entered. Column 2 shows the molecular weights of the components.
Column 3 is column 1 divided by column 2. Column 4 is the relationship between the moles of oxygen and the moles of the constituent in the particular chemical formula involved. Column 5 is column 3 multiplied by column 4. Column 5 divided by column 4 yields the values in the four right-hand columns.
The excess air 12 percent in this example is determined from flue gas analysis. The moles per mole of water vapor in the combustion air are determined from the relative humidity and temperature of the combustion air. The mean specific heat MJ can be determined for each. Air thru cooled walls must be used for combustion if reduction in radiation loss is to be made.
With the tabulation shown, the first 5 of the 8 losses listed in Figure are determined. Heat loss from carbon in the refuse is calculated from the weight of ash per fuel unit and the percent carbon in the refuse. This determines the weight of carbon per fuel unit, which is then multiplied by 14,, a commonly used value for the heating value of carbon. For determining the loss for unburned combustible gas per fuel unit, the particular un- burned gas and its percentage by volume in the flue gases must be known.
If it is CO, the percent by volume as analyzed in the flue gas multiplied by the total number of moles in column 3 provides the number of moles of CO per fuel unit. This value multiplied by 28 molecular weight of CO provides the weight lbs of CO. This weight multiplied by the gross and also net heating value of CO gives the unburned gas loss.
For a boiler fired with solid fuel, an unaccounted for loss of 1. For a gaseous or liquid fuel boiler, the commonly used value is 1 percent.
Note that the percent radiation loss increases as the boiler is operated at reduced load. An analysis of these percentage values demonstrates that the heat loss from radiation for a particular boiler is essentially constant regardless of the boiler rating at the time. Excess Air 0 4. As used in Figures , , and , combustion efficiency is boiler efficiency before radiation loss and unaccounted for loss are deduced. Since the measurements used affect only the losses, a comparatively low percentage of the total heat input, measurement errors have a much smaller effect on the resulting boiler efficiency.
From a practical basis, a standard fuel analysis can usually be used without affecting the boiler efficiency more than approximately 1 percent. A practical method for quick use in the field is a simplified heat loss method that is based on curve fits of precalculated efficiency tables for a standard fuel.
The fuel analysis and the precalculated tables are given in Figures , 10, 11, and This shortcut method is shown in Figure If the fuel analysis is unknown, the result of this shortcut method may be as precise as the detailed calculation using a standard fuel analysis.
The simplified method requires a minimum of information. The curve in Figure demonstrates the large influence of the radiation loss as boiler size and percent boiler rating are reduced. The radiation loss is built into the boiler design, and the user cannot operate the boiler in any manner to reduce this loss.
The steam that is collected in the steam drum contains some droplets of boiler water that must be removed before the steam is delivered from the drum. Figure demonstrates in a general way how the water and steam are separated. As the steam-water mixture rises to the drum, internal baffles separate this mixture from the water that goes on to recirculate through the downcomer tubes.
The steam is liberated from the mixture and collects in the upper part of the drum. Before passing out of the drum, the steam passes through mechanical separation devices. The most sophisticated of these separators uses a centrifugal action that whirls the mixture with the steam emitted from the center and the heavier water from the outside.
When very dry steam is required, many of these devices will be found inside the drum along with simpler scrubber equipment. While it is not evident from the outside, the inside of the drum is often filled with such devices. A typical arrangement is shown in Figure After passing through the scrubbing devices for eliminating moisture droplets, the steam leaves the drum.
If the boiler has no superheater, the steam flows to a distribution header. All boilers feeding such a header must have a non-return valve at the boiler outlet.
If the boiler has an integral superheater, the steam will pass through the superheater before it leaves the boiler. Normal Wilter Level Note that Figure shows longitudinal piping for feedwater and continuous blowdown. The feedwater and continuous blowdown piping usually enter the boiler drum at one end.
Perforations in this piping distributes these flows longitudinally. This diagram shows two saturated steam boilers connected to a steam header. Boiler steam flow. If these were superheated steam boilers, a steam temperature mea- surement would also be shown.
At the outlet of each boiler is a non-return valve that prevents steam from the header from entering the boiler. The steam header is the collecting point for the steam from more than one boiler and the location from which the steam is distributed to the steam users. While two boilers are shown here, there could bf multiple boilers operating at the same pressure and feeding steam to the same header.
The pressure in the steam header is also normally measured. On the outlet side of the steam header, the steam may travel through many steam lines in its transit to the users of the steam. The basic need of the steam user is for heat energy. Steam is a convenient carrier of that energy. When the header, the boiler steam leads, and all the steam lines are pressured to the normal operation pressure, a certain quantity of steam and, therefore, heat energy is stored in that system.
Heat energy is stored in the water, steam, metal, refractory material, and insulation material of the boiler. The boiler steam space is filled with steam, which represents heat energy storage in the steam.
In this case there are no steam bubbles underneath the surface of the boiler water since no new steam is being produced. Heat energy is also stored in the boiler water. Since there are no steam bubbles, the entire water space below the normal level in the boiler drum is water at saturation pressure and temperature. At this time the boiler is also losing heat by radiation. As additional fuel and air are burned, the boiler steam output may be increased to percent or more of its rated value.
Note that as firing rate increases, the heat energy storage in metal, refractory, etc. The steam space of the boiler is increased due to the steam bubbles below the steam drum water surface, and this increases the energy storage in the boiler steam.
The steam bubbles subtract from the water volume, and this subtracts from the boiler water energy storage as boiler steam flow is increased. Another aspect of the reduction in boiler water volume is that the mass of water in the boiler is less at higher boiler steam flow rates. This is an important factor in the proper control of boiler feedwater.
The energy storage in the boiler acts the same as a flywheel, which is also an energy storage device. Table can be used for demonstration. Table Energy Storage Relationships Steam at psig As pressure is reduced, the water cannot exist at It immediately releases 9. The heat released causes an immediate generation of steam that carries a corresponding amount of heat. In this way heat is released from storage as the pressure drops and must be replaced in storage as the pressure increases.
Assume that the boiler contains 50, Ibs of water and that the pressure drop above occurs in 10 seconds. The Btu in the water that becomes steam is 9. This is the Btu value of approximately Ibs of steam. On an increasc in capacity. There are slight delays in the actions of the control equipment. If the boiler steaming rate were , Ibs per hour, then the steaming rate demand could be doubled in 10 seconds with no increase in fuel and combustion air.
The drop in steam pressure would be less than 20 psi since the steam volume and boiler parts would also give up energy. When increasing or decreasing load, the amount of energy in storage must change. Over- firing and under-firing on a load change restores borrowed energy and readjusts energy storage to the proper level for the new load. If a boiler is not equipped with a superheater, the steam output is saturated steam. The superheater is a secondary heat exchanger that accepts saturated steam from the boiler and, by extracting heat from the flue gases, is able to add more sensible heat to the steam.
A superheater alters the control characteristics of a boiler operating at a given pressure. By changing the specific volume of the output steam. The change in the effect on steam pressure is related to the change in specific volume.
As they open valves to get more of the energy locked into the steam energy carrier, the pressure drops in the total storage system, triggering the release of some of the heat energy from storage.
The magnitude of the pressure drop depends on the relationship between the boiler water volume, total volume of the steam system, the magnitude of the steam demand, and the mag- nitude of the change in steam demand.
If the water volume is high, energy from the water is released to slow down the change in steam pressure. If the system volume is relatively low, the steam pressure change will be relatively high and vice versa.
The steam header pressure is the energy balance point between the energy demands of the steam users and the supply of fuel and air to the boilers to replenish the energy to the header system. At a constant steam flow or energy requirement, a constant pressure in the steam header indicates that energy supply and demand are in balance.
While the actual requirements are for energy, control systems work on the physical properties of pressure and temperature. A 1: 1 relationship between steam flow and energy flow is normally assumed. This is not true if the pressure and temperature change significantly. With this caveat, the balance is repre- sented by the statements that follow. K is a function of the system volume and steam specific volume related to the demand flow rate. The controls should be designed to regulate the fuel, air, and water to a boiler and maintain a desired steam pressure or hot water temperature while simultaneously optimizing the boiler efficiency.
During either normal or abnormal operation, the greater the sophistication of the controls, the greater the efficiency potential of the total boiler system. A control system can usually be upgraded in its functions by adding additional components or software.
Improving a control system is usually a cost-effective way to improve the operating efficiency of any boiler. Modulating controls are subdi- vided into two basic classes: positioning and metering. As the pressure or temperature drops to the switch setting, the gas valve is opened or the fuel pump started along with the combustion air fan motor.
The fire is ignited usually with a continuous pilot fame. The fuel and air continue operating at full firing rate capacity, and thc pressure or temperature rises until the switch contact is opened. Although such a system may maintain steam pressure or hot water temperature within acceptable limits, combustion is not controlled because combustion efficiency while firing is a result of mechanical burner adjustment.
When the burner is on, the excess air is sub. Air temperature and relative humidity Air supply pressure Barometric pressure Mechanical adjustment tolerances. In addition, each time the burner is off, cold air passes through the boiler carrying heat up the stack unless the flue damper is closed.
Figure 8- 1 represents how the oniof system works. Such a system has three steam pressure or hot water temperature set- tings: 1 Stop fire or off 2 Start boiler and go to low fire or stop high fire and go to low fire 3 Start high fire This system will hold the steam pressure or the hot water temperature within closer tol- erances of the desired steam pressure or hot water temperature.
It will get out of tune when any of the fuel and air conditions change from those prcsent when the burner was set. Firing Rate Demand for Industrial Boilers Modulating control is a basic improvement in controlling combustion and feedwater. A continuous control signal is generated by a controller connected to the steam or hot water piping system. Reductions in steam pressure or hot water temperature increase the output signal, which calls for a proportionate increase in firing rate.
Modulating control is an improvement because the fuel and air Btu input requirements and the Btu of the steam or hot water output of the boiler are continuously matched. The action of such a control system under the same load conditions of Figure and Figure is shown in Figure Because matching the input and output Btu requirements is improved, the steam pressure or hot water temperature is maintained within closer tolerances than is possible with the pre- viously discussed control systems.
The weighted average flue gas temperature is lower, so boiler efficiency is greater. Table compares the efficiency of boilers with the different systems while operating under the indicated load conditions.
The influences of changes in the condition of fuel and air have been eliminated by assuming a 10 percent excess air and-a constant flue gas temperature for each of the loads or firing rates that would occur. Although each boiler will have its own characteristics of excess air as opposed to flue gas temperature, the table is typical for a gas-fired boiler with the efficiency calculations based on to degrees flue gas temperature over the 25 percent to percent load range.
The table represents control systems operating ideally with no variation in excess air. Therefore, results are the same for all systems. In the middle range, efficiency clearly improves as control sophistication is increased. The benefit of modulating control is clearly established in Table For the simpler systems, a.
Figure demonstrates this method for regulating the firing rate using steam pressure. In some installations a constant steam flow may be required for one or more boilers in combination, while other boilers connected to the same header are used for controlling steam pressure.
It is also possible to arrange the system as shown in Figure so that the control for a particular boiler can be switched between steam pressure and steam flow control. The switch- ing procedure would require the boiler operator to switch the control to manual, adjust the set point to the desired value of the variable being switched to, operate the transfer switch, and then transfer the control back to automatic operation.
In either steam pressure or steam flow, a change in these variables is equated to a system demand for energy. Figure is a diagram of a change in steam flow rate, firing rate, and steam pressure with respect to time.
This diagram is useful in analyzing the tuning requirements of the loop. Sup- pose, as shown, the steam pressure transmitter has a range of 0 to psig for a 0 to percent output signal and that at a constant steam flow rate the firing rate is 90 percent of its range when steam flow is percent of its range.
This signal must be amplified to produce a change in the firing rate. Under steady-state conditions the firing rate change for the 10 percent steam flow rate change is approximately 9 percent of its range. As the load is increased, even a step change as shown here, the steam pressure will change.
I I Set point. This is the result of the initial load change being partly satisfied from energy storage. The initial firing rate change is thus a slightly delayed and reduced effect, since energy cannot be withdrawn from storage without a drop in pressure. In addition, the process takes time to convert the fuel energy and transfer it to the water in the boiler. Until the rate of withdrawal from storage balances the effect of increased firing rate, the steam pressure will continue to fall.
When the pressure stabilizes, the net result is that energy storage has been reduced. Steam pressure controller gain - 3.
This withdrawal from storage must be paid back by temporary overfiring. A load increase also requires overfiring to add the required additional energy storage that will allow the pres- sure to return to its set point. The magnitude of the desired temporary overfiring is usually a minimum of approximately 25 percent of the steady-state firing rate change, or 2. The 9 percent steady-state firing rate increase is thus increased to a needcd 1 1. Since the multiplier is 1 1.
Note that if the steam pressure transmitter had a maximum range of 0 to psig, the deviation would have been 0. Upon a reduction in steam flow, underfiring would have been necessary to adjust the system energy storage. For tuning such a steam pressure controller, a typical controller gain of4. The optimum gain will be determined by the ratio of boiler capacity to boiler-header energy capacity and t o scaling factors of the transmitters used.
The optimum integral setting will be approximately equal to the time constant one fifth of total time of the particular steam generation proce In this case, since the time constant is several minutes, the integral value in repeats per minute will be less than 1. The optimum controller tuning may not be that which will produce the optitnuin steain pressure pattern.
In many cases it is possible to obtain improved steam pressure control at the expense of boiler operating efficiency. Increasing the controller gain may produce oscillations of the fuel flow and the air flow that may improve steam pressure control while decreasing efficiency due to the oscillations.
The degree to which this may occur is diferent for different installations. The resolution of this question inust be based on the judgment of the proccss- experienced individual who is responsible for the controller tuning.
If steam flow is the controlled variable, the gain of the controller can be greater than that of a typical flow control loop because the integral time is much longer.
In this case a good starting point is 1. Since the integral value is related to the process time constant, it will approximate the value of the pressure control integral value. The output of the controller is called the firing rate demand or the energy input demand for the boiler. Development of a proper firing rate demand signal is of primary importance since all control of fuel and air is directed from this master signal.
The controller is therefore called the master controller. Because of the importance of this controller, a number of more sophisticated configurations are available. The use of these more complex arrangements results in greater precision of the firing rate demand input energy demand control signal and im- provement in the steam pressure control.
One of the two most frequently used variations is shown in Figure In this arrangement the steam flow a is the feedfor- ward demand.
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