Boiler Control System

Chapter 8

Boiler Control System Chapter Outline 1 Basic Control Requirement 1.1 Introduction 1.2 Transmitter Selection 2 Steam Pressure Control With Load Index 2.1 Objective 2.2 Discussion 2.3 Control Loop Description 3 Air Flow Control 3.1 Objective 3.2 Discussion 3.3 Control Loop Description 4 Fuel Flow Control 4.1 Objective 4.2 Discussion 4.3 Control Loop Description 4.4 Fuel Flow Controls for Tangential Tilt Burner Boilers 5 Coal Mill Control—Mill Air Flow Control (for TT Boiler) 5.1 General 5.2 Mill Temperature Control 5.3 Mill Control (Ball-Tube Mill) 6 Furnace Draft Control 6.1 Objective 6.2 Discussion 6.3 Control Loop Description 7 Drum Level Control, Feed Water Control 7.1 Objective 7.2 Discussion 7.3 Control Loop Description 8 Superheater Temperature Control 8.1 Objective

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1 BASIC CONTROL REQUIREMENT 1.1

Introduction

Modulating controls in a power plant is extremely important. It is always advisable to the designer to frame a basic control philosophy before developing a control loop. In the subsequent sections, brief discussions on the same are presented. All the control loops discussed in the book shall cover the following points. Although this is stated in connection

8.2 Discussion 8.3 Control Loop Description 9 Reheat Temperature Control 9.1 Objective 9.2 Discussion 9.3 Control Loop Description 9.4 Other Reheat Steam Temperature Controls 10 Miscellaneous Boiler Controls Including Overfire Air Damper 10.1 General 10.2 Objective 10.3 Discussion 10.4 Auxiliary Steam (BAS) 10.5 Soot Blowing Steam PR and SCAPH Pressure Control 10.6 SOx and NOx Control 10.7 Fuel Oil Pressure Control 11 HP-LP Bypass System 11.1 Objective 11.2 Discussion 11.3 Control Loop Description 12 Boiler OLCS: Introduction to Interlock and Protection of Boiler BMS, SADC, SB Control 12.1 Boiler OLCS 12.2 OLCS in SADC 12.3 OLCS in Soot Blower (SB) Control 12.4 Burner Management System (BMS/FSSS) 12.5 Secondary Air Damper Control 12.6 Soot Blowing System Bibliography

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with boiler control, it is applicable to all the control loops discussed in Chapters 9–11 also. l

l l

l

The objective of the control loop with relation to control parameters, manipulating variables, and final control elements (FCEs). Description of the loop/subloops. Automatic and manual operation, tripping to manual due to transmitter/sensor failure, as discussed in clause 1.2. Protection, interlock, and special features (If any).

Power Plant Instrumentation and Control Handbook. https://doi.org/10.1016/B978-0-12-819504-8.00008-1 © 2019 Elsevier Ltd. All rights reserved.

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1.2

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Transmitter Selection

Most of the control loops in power plants are offered with redundancies in transmitters, as discussed in clause no. 1.7 of Chapter 3. Now, the control loops often trip to manual on account of failure of these transmitters in different ways. Any transmitter failure shall be alarmed in the operator’s monitor. In the next subsections, the basic philosophy of tripping the control loop to manual under different conditions of transmitters is discussed, and this is applicable to all the control loops.

1.2.1 Control Loop to Manual in Case of One of Two Selection While operating in auto, the loop shall trip to manual in any of the following events: (i) Both transmitters fail (for example, out of range 4 mA > O/P > 20 mA). (ii) Both transmitters are healthy but the deviation between them is too high. (iii) Operator has selected any one transmitter for control (for some reason) and it fails. Now, the operator may select the other transmitter (if healthy) and put the loop back to auto. (iv) Average value of transmitter outputs selected and one transmitter fails (may be out of range) and the other could automatically be selected in auto, depending on the philosophy adapted.

1.2.2 Control Loop to Manual in Case of Two of Three Selection While operating in auto, the loop shall trip to manual in any one of the following events: (i) If the median or average is selected and two transmitters fail (e.g., out of range), the other could automatically be selected in auto, depending on the philosophy adapted. (ii) The operator has selected any one transmitter for control (for some reason) and it fails. Now, the operator may select the average (or median) or any of the other two transmitters and put the loop back to auto, provided the other transmitter is healthy. (iii) When the average/median of transmitters is selected and one transmitter fails (may be out of range), the average/median of the other two other could automatically be selected or the operator can select any of the two healthy transmitters manually, depending on philosophy adapted. a. Utility functions associated with the control loops: Now, as control systems are implemented with state-of-the-art technology, a few utility functions can be implemented easily through system software. A few such conditions have been

discussed, and would be followed as a general philosophy unless stated otherwise against any loop. i. Trip to Manual: Whenever the auto enable (release to auto) signal is absent, the loop will be forced to manual and cannot be put to auto by the operator until the auto enable signal is restored. An “auto enable” signal missing alarm may be generated in the diagnostic or any other monitor. In case any protection runback/forced open/ close condition exists or appears in the A/M station, the operator shall not be able to reverse the command. The same will be situation in case of directional blocking due to run up or run down protection rising from the failure of the main auxiliary. ii. In certain control systems having three-tier password protection, it may be possible for the engineer to reverse a few of these commands, but in all such cases, the engineer’s intervention will not only be alarmed but will be put on record with time stamping. iii. Generally, all output of the control loops is monitored against time. If the feedback of the control action does not reach the loop within the preset specified time, after the control command has been issued, or there is deviation between the command and control action, then the same may be alarmed at the monitor. iv. All set point reasonability are checked in the loop and in case of mismatch will be alarmed in the monitor. v. In case of changeover, the contact does not reach either end and an alarm shall be generated in the monitor as a noncoincidence error. b. Position Signal: All the control (modulating) valves shall have a position transmitter for position indication at the DCS monitor. In some of the loops discussed in this book, no feedback from the FCE position is taken to balance the loop (instead, the feedback is taken through the process parameter—a general convention) for a better steady-state response. The legend sheets are presented in Fig. 8.1 and are applicable to all control loop strategies depicted in the relevant chapters.

2 STEAM PRESSURE CONTROL WITH LOAD INDEX General For any steam-generation plant, steam pressure is the most vital parameter that indicates the state of balance between the supply and demand for steam, which, in other

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FIG. 8.1 Auto control loop system legend.

words, can be stated as the supply of heat input or fuel and the output as steam withdrawal from the system for various utilities like heating purpose or supplying to turbine for generation of power. In case supply exceeds demand, the pressure obviously increases and vice versa. The control loop strategies discussed in this chapter are for subcritical thermal power stations, that is, with a drum boiler.

2.1

Objective

The steam pressure control with load index as the feed forward signal is provided to maintain the main steam pressure in relation to combustion control. For a thermal power plant, it is the throttle steam pressure that is maintained at a fixed pressure or at a variable pressure for a sliding pressure control strategy.

2.2

Discussion

In the early low-pressure boilers stages with less development regarding superheaters, the measuring point of the steam pressure control was the drum itself. In a multiple steam generators interconnected, the common steam header pressure was the controlled parameter for each boiler with their individual bias setting to suit the prevailing site condition.

For the utility plants with individual turbines for any boiler, the very point of measurement for control purposes is the turbine inlet throttle pressure. The boiler control system in general is to take care of the numerous aspects that cover the following requirements: (i) Integration with the coordinated control system (CCS) combining turbine and Generator for MW control. (ii) Combustion control with fuel and air control having a lead-lag control strategy. (iii) Burner management system (BMS). (iv) Drum or start-up separator (for a once-through SG plant) level control. (v) Superheater/reheater steam temperature control. (vi) Adequate display and data for the operator to continue in case of emergency and for the system engineers for analysis of any catastrophic situation. During certain periods of time in the past, the normal practice was to provide separate and independent subsystem control for the boiler and turbine/generator with no or minimal coordination between them. Nowadays, the CCS has come up with a complete solution having the main and ultimate demand controller output issued simultaneously to each subsystem, ensuring more responsive control loops for better results.

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Coordinating the entire plant with all the subsystems in tandem requires an intimate knowledge of these systems and the selection of the appropriate operating mode to make them work together. The main motivation behind the idea is to take care of the time lag and minimize the effect of interactions among the above subsystems. The time lag normally refers to the boiler, which has enormous thermal mass and is therefore relatively slow to respond to the requirement. Turbines, on the other hand, are very compact and almost immediately respond to any changes called for by the control system or operator’s action. The coordinated control loop, when operated under a boiler follow mode in which a load demand signal, as provided by the operator or load dispatch controls (LDC), controlled the position of the turbine governor or control valves. The throttle or system steam pressure changes and the boiler controller accordingly takes corrective action to control the input of fuel, combustion air, and feed water to maintain the system steam pressure at a predetermined fixed or variable level. Alternatively, in a turbine follow mode system where the load demand is issued to the boiler whereby the fuel, air and water inputs were respectively controlled. As the steam pressure varies due to changes in heat input, the turbine controller adjusts the position of the governor valve to set the system steam pressure at a preset value. The main intention behind employing a turbine follow system is to maintain throttle pressure at all times, but the overall system performance is not regarded as a very efficient process. This is because the turbine follow mode is not capable of making maximum use of the stored energy in the boiler in order to maintain a constant pressure. A detailed discussion is included in clause no. 1.1 of Chapter 10. However, the boiler control in relation to the total control system has been designed with the aim to cope with the everincreasing power demand with good frequency control over the entire range. In addition to overall systems requirements, there must be a provision so as to extract the maximum energy from the boiler, having well-defined set limits within which the boiler is assured for efficient and safe operation. The basic concept of a coordinated control system is to issue the load demand signals simultaneously to the boiler control system and to the turbine control system as a feed forward signal. This is utilized mainly for minor or trim corrections in response to detection of errors in the throttle pressure, megawatt, and frequency adjustments. The most important application of this feed forward signal is the use of a control philosophy to reduce interaction and to increase the possibilities of taking out the best dynamic response. Utilizing this signal is always advantageous as the same senses the load changes very fast and enables corrective action before any significant errors crop up. Feedback controllers may be used as a final or further trim at the appropriate level to make amends for minor deviations and adverse effects in getting a better steady-state response.

To be more specific, the throttle pressure is measured through redundant transmitters and compared with a fixed or variable set point, which provides the throttle pressure error. It is subsequently fed to a controller with integral action before being applied to the turbine control system. The throttle pressure error signal is utilized to readjust the load set point. On the other hand, the MW output delivered by the turbine is measured and compared with the MW set value to provide megawatt error. It is subsequently fed to a controller with integral action and is used along with the throttle pressure error signal before being applied to the boiler control system for the subsequent control of the air and fuel inputs to the boiler. The details are discussed in different sections of Chapter 10.

2.3

Control Loop Description

As indicated earlier, the boiler steam pressure control system is the basic system that is meant for maintaining the pressure, be it the main steam throttle pressure or the header pressure (multiboiler in a single-header configuration), by adjusting the fuel and air input in a bid to supply proper heat input as per the demand sensed by the change in the above steam pressure. This control loop is actually a part of the boiler combustion control loop, and quite a few varieties of such loops to match the requirements of the individual boiler concerned have been developed over the years since inception. The final choice of configuration depends upon so many factors such as the type of fuels; the firing system; different subsystems such as the boiler, turbine, etc.; the pattern of load demands; and the layout of different subsystems and associated accessories. Fig. 8.2 may be referred for a schematic representation of the idea for implementing the control loop in a typical 250 MW plant having a drum boiler with a down shot opposed fired (fossil/coal) furnace (Babcock design) with occasional oil support. The control loop may vary with the manufacturer’s special design, but the basic idea would remain the same. A similar loop with little difference in philosophy is shown in Fig. 8.11. Here, the main steam pressure is measured with triple redundancy and sent to the coordinated control system after the necessary voting circuit. The main steam pressure is compared with the set point, which may be a fixed set point or a variable set point depending on the power plant unit configuration and type of different subsystem such as the boiler, turbine, etc. The main steam pressure error signal is then fed to a controller with the output having built-in proportional, integral, and derivative action. Controller tuning is normally with an auto tuner, but the system engineers may tune the same to suit the particular site condition. The controller output signal is then trimmed suitably through a function algorithm whose other input is the

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FIG. 8.2 Steam pressure control with load index.

characterized signal from the FW temperature at the economizer inlet and feed forward signal from the derivative of the boiler load demand signal generated in the coordinated control system (Chapter 10), as indicated in Fig. 10.2. The feed water temperature at the economizer inlet is also a part of the feed forward signal generated within the boiler control subsystem, meaning the enthalpy carried into the boiler by the feed water from the outside. When the temperature is less, the heat input demand would be more and vice versa. Another trimming signal is taken from the furnace draft/ pressure signal with sufficient redundancy before voting. The loading of the boiler corrects itself in accordance with the furnace’s present running condition, that is, whether further loading or unloading is required to maintain the furnace pressure. With the furnace pressure always fluctuating, this signal is fed through a time delay and filter circuit to avoid oscillation in the controller output. The trimmed output signal is the load demand for the air flow controller. The same signal is also utilized as the fuel flow demand but not before passing through a minimum selector with the total air flow as the other input, ensuring that fuel flow demand or actual flow can never be more than the air flow demand or actual flow. The control philosophy in a tangential tilt burner, as shown in Fig. 8.11 may be different as utilized in another 250 MW power plant with TT burners. Here, the main steam pressure demand is compared with the pressure (fixed or

sliding) set point generating the error signal, which is fed directly into a PI controller and the output of the controller is the desired pressure demand signal. In order to make the loop more responsive, the load index signal is added at the output of the controller. Because the loop is tuned with the load index signal at the output, any change in demand will affect the loop at the same time the derivative signal, which always contributes noise, has been eliminated. As shown, there could be a number of parameters to be considered as the load index signal: l

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3

Steam flow, if measured (in higher MW plants, this may not be measured due to permanent loss in the flow element). First-stage pressure of the turbine added with highpressure bypass (HPBP) flow (if partial HPBP is allowed). Generator load.

AIR FLOW CONTROL

General Air flow control is a very vital part of the combustion control system, which generates the demand and ensures the adequate air flow required for complete combustion of fuels, as requisitioned by the combustion control system for keeping the steam pressure at its desired value.

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Power Plant Instrumentation and Control Handbook

Objective

The air flow control is provided to supply the total air flow to the exact quantity that satisfies the demand of the fuel firing rate considering the stoichiometric ratio (chemically correct or perfect ideal air-fuel ratio) and some excess air to guarantee complete combustion. The control loop discussed here actually computes the total required air flow in relation to the mill-wise air flow demand; when the relevant PA flow is subtracted from it, the balance amount is regarded as the secondary air demand required for stoichiometric combustion.

3.2

Discussion

Air flow control has been considered to be very important for any firing system. Inadequate air flow means the exhaust flue gas would contain the environment pollutant carbon monoxide due to incomplete combustion, which is not allowed by regulatory boards. Lack of air flow also means more fuel cost and less efficiency. For this reason, some amount of excess air is provided for the firing process to take place with the condition of as near to complete combustion as possible. On the other hand, too much excess air would not take part in the combustion process at all but would carry over the extra heat as simply waste, causing less efficiency toward the cost of equivalent fuel.

FIG. 8.3 Air flow control/SADC control 1.

3.3

Control Loop Description

Figs. 8.3–8.6 may be referred to for a typical schematic representation of the control loops in a typical 250 MW plant with a drum boiler and fossil (coal)-fired furnace with occasional oil support (Babcock design), which may vary with the manufacturers’ special design and fuel type.

3.3.1 Measurement of Different Parameters 3.3.1.1 Total Air Flow Air flow is measured by different types of flow elements normally dictated by the boiler manufacturer. For plants having more than one forced draft fans whose suction or discharge points are selected for measurements are then summated to achieve total flow. Triple redundant flow signal after necessary voting circuit is density compensated with redundant temperature transmitters before square rooted for getting linear signal. Pressure compensation is not required in this case. This signal is also utilized for fuel flow control and furnace draft control; binary signals derived from this signal may also be used for the BMS, as shown in Fig. 8.3. 3.3.1.2 Oxygen Percentage in Flue Gas This measurement forms an important part in the air flow control philosophy so far as complete combustion and excess air presence is concerned. Fig. 8.5 indicates a

Boiler Control System Chapter

triple-redundant measurement and voting circuit accordingly. The strategic tapping point of oxygen percentage measurement is also important and varies according to different schools of thought. The probable points may be at the economizer inlet, outlet, or the air heater inlet where the flue gas temperature would vary, and so the type of transmitters may also. Normally in situ or online instruments are preferred over sampling measurements for a faster response. 3.3.1.3 Measurement of Feed Water Temperature at Economizer Inlet This measurement (Fig. 8.5) with sufficient redundancy and a voting circuit is utilized as a feed forward signal and a trimming factor for the steam flow signal. This characterized steam flow signal (from Fig. 8.27) forms the boiler load index. 3.3.1.4 Measurement of Secondary Air Flow Fig. 8.4 envisages two numbers and secondary air dampers (SAD) catering to the combustion air required for mill-wise coal flow. The air flow in each line is measured with redundancy and a voting circuit and summated to achieve the total secondary air flow meant for the combustion air to each mill. Density compensation may be provided, depending upon the excursion of temperature. The mill-wise secondary air flow is now corrected as per the oxygen trimming signal (oxygen percentage in flue gas) and becomes the process variable for the secondary air flow controller. The set value formation of this controller is dependent on the load.

3.3.2 Different Controls 3.3.2.1

Oxygen Trimming Controller

Fig. 8.5 may be referred to as the schematic representation of oxygen trimming in the control strategy. The combustion process needs excess air as discussed earlier; the residual oxygen present in the flue gas is an index of the same. This excess percentage of oxygen toward the optimum combustion condition is not a constant value but depends on the percentage of load. An approximate value is around 4% at boiler load <60% and at loads >60%, the presence of oxygen becomes gradually lesser and is about 1.5%– 2% nearing 75–100% load. The graph of excess percentage of oxygen versus percentage of load is depicted in Fig. 8.5. The main steam flow is taken (Fig. 8.27) as the boiler load with sufficient approximation (no leakage, no intermediate requirement, etc.) and corrected with the signal from the feed water temperature at the economizer inlet as the feed forward signal. After correction, the boiler load is converted to percentage of oxygen in the flue gas through the algorithm representing the graph indicated above. A bias is added to it as part of finer tuning or adjustment to suit site

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conditions to arrive at the desired set value of oxygen percentage. A selector switch makes provisions for a manual set point. A set point with oxygen percentage generates the error, which is connected to the controller with the P + I + D output option. To prevent overcorrection, the controller output is passed through a high/low limiter with hand set limit values corresponding to a particular boiler and sent for air flow control as well as supplying combustion air to all the mills’ fuel control.

3.3.2.2 Secondary Air (SA) Flow Controller As discussed above, there are two SAD provided in the air flow path to control and supply combustion air to each pulverizer/mill as per the command issued by the relevant controller. Both the air flow demand and the characterized feeder speed signal as generated in Fig. 8.9 are passed through a maximum selector option so as to ensure higher air flow in both the increasing and decreasing load. The air flow demand as derived is the total combustion air flow required for each mill, including the PA flow as provided by separate PA fans. For that reason, the PA flow pertaining to each mill (Fig. 8.9) is subtracted from the above air flow demand to generate the actual air flow requirement or set point for the secondary air flow controller. The controller output (Fig. 8.4) then passes through a maximum selector option with other signals related to minimum air flow, pulverized fuel position, oil position, etc. These other signals are analog but triggered from the binary signals initiated by the particular boiler operating conditions, which are: (i) A dedicated controller is provided for maintaining the SA flow at 45% (typical value) when the requirement is initiated by the BMS related to the pulverized fuel in the operating condition. (ii) A dedicated controller is provided for maintaining the SA flow at 10% (typical value) when the requirement is initiated by the BMS related to oil as fuel in the operating condition. (iii) A dedicated controller is provided for maintaining the SA flow at 25% (typical value) when requirement is initiated by the BMS related to furnace safety conditions. These typical values may vary from plant to plant; the ultimate strategy is to ensure an air-rich condition throughout the operation of the boiler subsystem without fire hazards and with optimum efficient output. The final output signal from the above maximum selector then drives the respective SAD. Similar loops are envisaged for each pulverizer mill group, according to the boiler load.

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FIG. 8.4 Air flow control/SADC control 2.

FIG. 8.5 Oxygen trimming in air flow control/SADC control.

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FIG. 8.6 Hot air duct pressure control (total air flow control).

3.3.2.3

Hot Air Duct Pressure Controller

Normally, two forced draft (FD) fans are provided with about 60% (typical) load-bearing capacity to supply the complete combustion air for all types of fuels. There are several FCEs that are deployed for controlling the air requirements, such as the FD fan vane, impeller, damper, etc. In this control loop philosophy, FD fans vanes are envisaged as the FCE and modulate to control the hot air duct pressure. FD fans suck air from the atmosphere and heat it through air heaters before it is used for combustion. The hot air duct pressure normally decreases at a higher load and it becomes difficult to supply adequate air flow by the downstream control elements. This pressure is maintained at its desired value so that the downward SADs can control the air flow smoothly. The air pressure in the hot air duct is measured with a redundancy and voting circuit to form the process variable. The steam flow signal as generated from Fig. 8.27 for the drum level control is considered the load index and characterized to act as the desired pressure set value. Necessary arrangements are done to take care of increasing the demand signal in case only one fan is on and running on auto mode when the running fan would take more load, within its capacity, than that of the load shared by two fans.

3.3.3 Alternative Air Flow Control Concept Boilers with tangential tilt (TT) burners (CE DESIGN) and independent FD fans and PA fans using cold PA systems. In Fig. 3.35, it is seen that the secondary/combustion air

from the FD fan gets heated at the air preheater (there may be a SCAPH before APH), and goes directly to the wind box of the furnace and then to the combustion chamber. There are a number of FCEs in the path. All the FCEs located in the wind box are responsible for air distribution at different elevations of the boiler, whereas the FCE associated with the FD fans is responsible for controlling the total quantity of combustion air (CA)/secondary air (SA) for the furnace. As stated earlier, even though these loops are responsible for the SA/CA controls, they do so after computing the total air flow (i.e., including PA flow) so that at any condition, the stoichiometric ratio is maintained. For a typical TT boiler, the cross-section of any corner of the wind box is what is shown in Fig. 3.33. Here, it is clear that double-lettered elevations will have auxiliary air dampers, and some of them will have a fuel air damper, whereas all single-lettered elevations have a fuel air damper. A short list of the FCEs is presented in Table 8.1. 3.3.3.1

Secondary Air Damper Control

The SADC is a part of the furnace safeguard and supervisory (FSSS) system. The basic purpose of this control is to distribute the total quantity of SA among the various elevations so to ensure proper combustion. As stated earlier, these dampers can be categorized as: l

Fuel air damper—Those dampers that regulate the air surrounding a fuel compartment.

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TABLE 8.1 FCEs for Combustion Air FCE Type

FCE Location

Control

Remarks

Fan impeller OR

FD fan

To control the total quantity of SA/CA for the boiler. Main modulating control loop and part of combustion control

Normally Pneumatic Power Cylinder to regulate flow by restriction

Fan inlet damper OR Speed control by VFD (Associated with FD Fan motor)

l

Electrical type—to regulate flow by speed control of the fan, more energy efficient

Auxiliary air (AA) damper

Wind box at double-lettered elevations

To maintain furnace wind box differential pressure (DP) so as to regulate and distribute SA/CA to the corresponding elevation during operation

Furnace wind box DP control loop in secondary air damper control (SADC) system—a part of FSSS

Fuel air (FA) damper

Wind box at single-lettered elevations (as well as in oil elevations, when oil firing is taking place, AA becomes FA)

To regulate the damper opening in proportion to the feeder speed or coal flow to the corresponding elevation so as to regulate and distribute SA/CA to the corresponding elevation during operation

Fuel air damper control loop (proportionate to coal flow) in secondary air damper control (SADC) system—a part of FSSS

Auxiliary air damper—Those dampers that regulate the air adjustment to the fuel compartment.

The main philosophy of control is that auxiliary air dampers in all elevations in a group are controlled in proportion to the fixed differential pressure between the wind box and the furnace, whereas the fuel air dampers of the four corners of each elevation are group-controlled proportionally to the rate of fuel fired in that elevation. During purging and at a lower load up to 30%, AA is regulated to maintain the wind box/furnace DP around 40–50 mm wcl. There is an exception: double-lettered elevations that have an oil burner (say AB, CD, EF, GH). When oil firing takes place at that elevation, the corresponding elevation damper will open at a fixed opening; otherwise they act as an AA. Normally, all fuel air dampers (FA) in single-lettered elevations are closed, but open after a small time delay (tube mill will be different) after the associated feeder starts, so as to ensure the availability of SA in the corresponding elevation.

3.

4.

5.

6. 7.

3.3.3.2 Air Flow Control Loop (Figs. 8.7 and 8.8) 1. Discussions: As stated earlier, the alternative discussed now is a cold PA system, that is, the PA does not have its suction from the SA/CA as was the case discussed earlier. Therefore, to compute the total air flow, the PA fan flow discussed later needs to be added to the SA/CA flow. 2. Normally (as shown in Fig. 3.35) there are two independent lines from FD fans that go to the wind box, and the air flow is measured in these lines after air

8.

preheaters. Aerofoils, Pitot tube or Piccolo tube flow elements may be deployed. DP transmitters in two of three (as shown) or one of two redundancies are required, as these are very vital parameters. Because these are hot SA/CAs, temperature measurements for density compensation are essential. Here also, the redundancy is shown in Fig. 8.7. It is recommended that, in case of redundancy for both parameters, compensation should be done with two of three (one of two) output signals so that a better result will be obtainable. Because FD fan pressure is low and there is not much chance of variation, pressure compensation has been avoided, s shown in Fig. 8.7. Both side-computed SA/CA flows are added to arrive at the total SA/CA computation. As discussed in clause no. 3.3.3.1.1, the PA flow is also added, as shown in Fig. 8.7. For a bowl mill, the individual mill PA flow computation, or for the Ball and tube mills, each side PA flow of each mill computation is done (to suit the possibilities of individual side operation of a mill) and added to constitute the total air flow to the furnace. The exact quantity of total air flow corresponding to fuel is necessary to ensure optimum combustion (correct stoichiometric ratio maintained). Because incomplete combustion may give rise to CO accumulation, which is very dangerous and can cause an explosion, it is customary to have little excess air (clause no. 3.2). For this reason, lead/lag circuits are used. Here, as shown in Fig. 8.8, the actual total fuel

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FIG. 8.7 Total air computation for secondary air flow control TT boiler.

flow is passed through a MAX selector where the air demand is also fed. When the fuel demand decreases, the air flow demand cannot decrease unless the actual fuel flow decreases (MAX circuit). Similarly, unless the air demand increases, the fuel flow cannot increase (MIN circuit as shown in Fig. 8.11). 9. In order to get the exact stoichiometric ratio as discussed in clause no. 3.2, the air demand is modified/

FIG. 8.8 Secondary air and oxygen trimming control TT boiler.

trimmed with excess O2 in the flue gas. There are two schools of thought: one believes this trimming should be done on the demand side (as done and as shown in Fig. 8.8) while the other thinks it is better to do the same in the actual measurement circuit, as discussed in clause no. 3.3.2.1. Now, corresponding to the operating load of the boiler, there will be a desired set value for O2. So, the set point is given as a function of

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load, as shown in Fig. 8.8. At a lower load, this may be a fixed value, so two set points have been shown through a selector switch. The O2 controller (PI) provides the trimming signal for demand modification. This modified demand signal is checked against the minimum value (30%) and allowed to enter the error generator. 10. Error generator output is fed to a PI controller to generate a demand signal for the FCE associated with the FD fans. There could be various options, as shown in Fig. 8.8 and given in Table 8.1.

4 FUEL FLOW CONTROL General A fuel flow control system is very important and a vital part of the combustion control system as air flow control system. On getting the boiler load demand signal as a command from the steam pressure controller with other influences, it generates the fuel flow demand after ensuring the necessary air flow is available for complete combustion of fuels to keep the steam pressure at its desired value.

4.1

Objective

The fuel flow control is provided to supply fuels in the exact quantity that would satisfy the demand of the fuel firing rate in close coordination with the air flow control system to ensure the stoichiometric ratio is maintained with some excess air flow throughout the combustion process. This control loop guarantees that the fuel flow must decrease prior to the air flow for a decreasing load demand, and the air flow must increase prior to the fuel flow for an increasing load demand so that an air-rich condition always prevails for safe and complete combustion.

4.2

Discussion

Air flow control is always associated with fuel flow control for various reasons. The increasing cost of fuels has ever been the center of consideration as the fuel quantity is always affected by incomplete combustion or too much excess air. Nevertheless, the percentage of carbon monoxide in the flue gas at the chimney outlet is also a serious matter of concern. The local/state pollution control boards are empowered to stop any (power) plant on allegations of polluting the environment. Irrespective of mill type, the ultimate products, that is, powdered/pulverized fuel (PF), is transported by blowing pressurized and hot air called hot primary air through the mills up to the furnace. Separate fans performing this transportation duty are called primary air fans (PAF). Manufacturers, plant design, and the layout of the steam generator unit decide the number of PAFs. There may be two or three centralized PAFs forming a common header

catering to each mill, whereas the alternative design envisages an individual/dedicated fan for each mill. The control loop (Fig. 8.10) to be discussed here is with three centralized PA fans, but the control loop philosophy would remain almost the same with some minor modifications. The suction of PA fans may be directly from the atmosphere or from the FD fans common discharge header. It is sent to a common trisector/separate primary air heater (AH), which is called the cold PA system. In the cold PA system, the PA discharge header is common and the major part of the PA fan discharge is sent to the PA heater for gaining heat. The rest acts as the cooling medium for controlling the PA temperature at a specific designed value with millwise hot and cold air control dampers. When the PA fan suctions are connected to the common FD fans discharge header after the bisector AH, it is termed a hot PA system. In a hot PA system, a cold PA common header is formed before the AH. Mill-wise or common PA fans are provided to transport fuel at a controlled temperature through the hot and cold air dampers (CADs). The large fossil-fired power stations mainly use coal or lignite as the main fuel. heavy fuel oil (LSHS) or light diesel oil (LDO) is also used as a supporting fuel. At the time of initial start-up, LDO is used to start the firing. However, in many plants, the use of LDO has been eliminated by high energy arc (HEA) igniters, even at the time of start-up, the HFO/LSHS can be used. Poor-quality or water-soaked (in the rainy season) PF also prompt the operator for oil support. For heavy fuel oil (HFO) or an LSHS-fired boiler, it is necessary to keep these oils at a higher than ambient temperature to keep the viscosity at an acceptable limit. For this purpose, steam tracing or electrical heating is required for the supply pipe line up to the furnace ring header or the front/rear header and the return oil line also down to the pump suction.

4.3

Control Loop Description (Fig. 8.9)

The control loop may vary to some extent with the manufacturers’ special design and fuel type, but the basic idea would remain the same; related control loops are presented for TT type boilers also. The control loop for ball tube mills is discussed in a separate section.

4.3.1 Measurement of Different Parameters (Fig. 8.9) 4.3.1.1

Primary Air Flow

The accurate PA flow measurement is very important, as it is utilized as the demand for coal/pulverized fuel (PF) flow in the control loop under consideration. Different types of flow elements are also used for measuring the PA flow,

Boiler Control System Chapter

which is normally dictated by the boiler manufacturer as per their standard scope of supply. Sufficient redundancy is provided (typically shown as triple redundant); after the necessary voting circuit, the output is density-compensated through temperature transmitters with a necessary redundancy and voting circuit and square rooted to provide a linear signal; pressure compensation is not required in this case. A computed signal is also utilized for air flow/SADC (Fig. 8.4) and for formation of the controller set point of the feeder speed controller.

4.3.2 Different Controllers

4.3.1.2 Measurement of Feeder Speed Accurate feeder speed signal being the measured/process variables is an essential part of fuel flow control strategy as this signal would enable the boiler load control to ensure the much needed supply of fuel flow. The bed height remains almost constant (by some external arrangement) and hence the feeder speed is equivalent to the quantity of material on the feeder. This measured signal, after the necessary redundancy (typically shown as triple redundant) and voting circuit, is sent to the speed controller.

4.3.2.2

4.3.1.3 Measurement of Differential Pressure Across the Mill This measurement with sufficient redundancy and voting circuit is utilized as a means of feed forward signal and utilized as a trimming factor for feeder speed demand signal (Babcock design). 4.3.1.4

Measurement of Oil Consumption

One flow element in each supply and return oil line is provided. The difference between the two flow elements’ signals is the actual oil consumption through the oil burners. As the requirement is for a short time, redundant transmitters have not been envisaged. 4.3.1.5

Measurement of Primary Air Pressure

This parameter with sufficient redundant measurements and a voting circuit is utilized as a measured/process variable for the controller. 4.3.1.6

Generation of Secondary Air Flow Demand

All the feeder speeds representing PF flows are summated to get the total solid fuels being fired; the actual oil flow is added to the PF flow with proper adjustment toward the calorific value to reach the actual heat input. This summated value is auctioned with air flow demand (Fig. 8.4) in a maximum selector output of which constitutes the allimportant signal for the secondary air flow demand. As there are individual sets of SAD (Fig. 8.4) for each mill group, this same demand signal is utilized for all the mills.

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4.3.2.1 Primary Air Flow Controller This controller takes care of the PA flow according to the PA flow demand from the master pressure controller (Fig. 8.2) in relation to the boiler load demand. This signal being the set value, the actual density-corrected PA flow acts as the measured/process variable. The PA dampers are provided for each mill group and are modulated as per the individual controller output (adaptive controller or P + I + D tuning facility). Feeder Speed Controller

The feeder speed control loop (Fig. 8.9) is provided to vary the feeder speed, normally through the variable frequency drive (VFD) or any other suitable drive to meet the modified fuel demand. The fuel demand or set point is derived from the characterized PA flow. The primary air being the transporting medium for the solid fuel, the two flow signals have a particular relation or function of proportionality for a particular type of fuel. This relationship is exploited in the algorithm form where the PA flow constitutes the input and the output represents the equivalent feeder speed set point for the feeder speed controller. The actual feeder speed plays the role of a measured/process variable and the controller output (with P + I + D tuning facility) is further trimmed with a signal, which may be termed a feed forward signal. Whenever the load increases, the air flow (both secondary and primary) has to increase first, followed by the fuel flow. If there is a delay between the two actions or a substantial difference, the DP across the mill would become low compared to the PA flow. This difference in values is obtained through a subtraction function and acts as the abovementioned trimming signal of the controller output. This would enable increasing the feeder speed in advance to avoid a significant mismatch in complying with the actual fuel requirement. For a decreasing load, the DP across the mill would become high compared to the PA flow and would force a lowering of the feeder speed prior to the decreasing command coming out directly from the controller. 4.3.2.3 Primary Air Header Pressure Control (Fig. 8.10) This control system applies to the common PA system and the pressure controller gets a fixed or variable (to load) set point selection via the selector switch, as shown in Fig. 8.10. For variable set points, there are some options available for the designer: l

In case of fall and tube mills, the maximum position of the damper of the PA flow through the mill out of both sides of all mills (i.e., the maximum coal flow condition) may be taken as the set point so that the PA fan regulates itself to cater to the maximum demand.

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FIG. 8.9 Fuel flow control. l

l

Highest feeder speed condition for a bowl mill is mainly used in the TT burner boiler with a similar philosophy as discussed above. In some other cases, a base set point is added with the boiler load (the boiler load possible options are shown in Fig. 8.10) used as the set point.

The set point is compared with the actual PA header pressure to generate an error signal, which is fed to a P + I controller. The output of the controller regulates the working fan capacity by changing the fan speed through VFD or regulating the inlet vane/suction damper. Speed control is more efficient for obvious reasons such as lower loss. Controller output goes to the master A/M station so as to facilitate common manual operation. The final demand at the output of the A/M station (for both auto as well as common manual) is adjusted for gain depending on the number of PA fans in auto.

4.3.2.4 Coordination between Air Flow and Fuel Flow Controls These two control loops are extremely interrelated. It is well known that the combustion process in the furnace of steam generators requires oxygen, which comes from the air in the

atmosphere. To avoid incomplete combustion and inefficient operation of the plant, the air flow rate is very important, needing a close watch on its measurement and control along with the fuel flow. The boiler load controller gets its set value from the main steam pressure at an appropriate point near the turbine inlet. The controller output gets properly trimmed from the feed forward signal from the coordinated controller output. The trimmed signal (Fig. 8.2) is then regarded as demand for the secondary air flow, provided this boiler load demand is more than the fuel flow (Fig. 8.9). It is then sent to each mill group for SA controls. This signal representing the total air flow, the PA flow is subtracted to get the mill-wise SA demand only, and the subsequent controller ensures that the SA dampers are acting accordingly. The demand for PA flow, on the other hand, is generated from the above trimmed boiler load (from the master pressure control) signal and allowed to proceed further if this boiler load demand is less than the total air flow signal. This signal is then treated as the mill-wise PA flow set point. After the PA flow controller takes care of the PA flow, the feeder speed controller gets its set point from the characterized PA flow and regulates the fuel flow through the speed-changing device.

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FIG. 8.10 PA header pressure (fuel flow control).

From the above discussion about the generation of demand for air (SA) flow and fuel flow (via PA flow), it may be noticed that whenever the boiler load increases, the air (SA) flow increases first and then the PA/fuel flow increases whereas in a decreasing load, the PA/fuel flow decreases first and then the air (SA) flow decreases. This unique feature is called the lead-lag relationship between the air and fuel flow. This particular idea is maintained throughout so as to prevent unsafe boiler operation and happens to be the essence of the control philosophy.

4.4 Fuel Flow Controls for Tangential Tilt Burner Boilers Boilers with tangential tilt burners with bowl/ball and tube mills are discussed briefly, though the basic objective is the same as other boiler designs.

4.4.1 TT Boiler Master Demand Control (Fig. 8.11) MS pressure is the determining factor for the generation of fuel demand signal in conventional loops without a coordinate control concept. For plants having coordinate control, the demand signal is generated in the coordinate control

system, which is dealt with separately in Chapter 10 of this book. For direct control, a master pressure signal is generated from the turbine inlet pressure transmitters. The manual (fixed) set point or sliding set point (common in an OT Boiler) is compared with the measured pressure signal obtained from the two of three redundant circuits, as shown in Fig. 8.11. Normally, a sliding pressure set point slides/changes with the load from >60% load (below which the auto loop is practically ineffective); to be precise, between 70% and 90% mainly. Beyond this range, the set point is fixed. In a load regime >90%, the pressure is kept fixed as a cushion to meet the eventualities. During sliding pressure operation, governor valves are kept wide open (less pressure drop across the control valve) so that the turbine inlet pressure slides as per load. Supercritical/ultrasupercritical plants with OT boilers may go for a sliding pressure operation with the possibility of saving some energy. Thus, both options are shown in the drawing. The difference between the set point and measured value creates the error signal for the PI controller to generate the fuel demand signal. With the inertia of the boiler being higher in comparison to the system demand, the system load is taken as the feed forward. Because derivative signals are basically a source of high-frequency noise, the loop requires

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FIG. 8.11 Main steam pressure control—fuel demand—Tangential tilt boiler.

proper tuning with the boiler load as the feed forward is added to the demand from the master pressure controller to make the loop more responsive. A few options available to use as the load index are listed below: l

l

Steam flow (in larger boilers, steam flow may not be measured to avoid loss due to a permanent pressure drop). First-stage pressure/wheel chamber pressure, which is proportional to turbine load can be considered (with HP bypass flow where a partial bypass is envisaged in the system). In some places, a direct generator load is considered in place of first-stage pressure.

As discussed earlier, for actual fuel demand signal generation, it is necessary cross limiting fuel demand signal with Actual air flow, so that under all situations, air enriched condition prevails (i.e., for increasing load, air would increase first followed by fuel; for decreasing load, fuel is reduced first before air flow decreases). This is ensured by the MIN selector and the actual air flow. The fuel demand signal thus generated needs to gain correction for the number of mills in operation. The location of each of the measurement points is shown in Fig. 8.11. Generally, the fuel oil flow in the boiler is controlled by the oil pressure

control, discussed separately. Out of the total fuel flow, there may be some contribution from the oil flow also. Oil flow measurements are shown in Fig. 8.12. The difference between the supply line flow and the return line flow of HFO gives the net HFO flow; this flow along with the LDO flow (insignificant in reality) with the necessary calorific value correction computes the total oil support of the fuel. This is subtracted from the total fuel demand to compute the net coal demand in Fig. 8.11.

4.4.2 TT Boiler Fuel (Coal) Control Loop for Bowl Mill (Fig. 8.12) In bowl mills, which have very little holding capacity, the coal flow is computed by the feeder speed measured with the help of speed transmitters. To avoid a spurious signal, the feeder speed signal is passed through a low pass filter (LPF). A feeder speed signal is taken as valid only when the FSSS interlock permits, so that the preparatory stage flow signal is ignored. All feeder speed signals are summated and then compared with the net coal demand (Fig. 8.11) to generate the error signal for the PI controller whose output becomes the total coal demand signal at that instant. Immediately after the controller, the feeder master

Boiler Control System Chapter

A/M station provides the facility for common manual operation and the output (for both auto as well as common manual) is adjusted for gain depending on the numbers of feeders in auto, as shown in Fig. 8.12. Each of the feeder controls shall have its own A/M station to facilitate individual manual operation as well as adding bias. The output of each of these A/M station drives the feeder speed variator with the help of a pneumatic power cylinder or may drive the SCR controller for the gravimetric feeder. Both options are shown in Fig. 8.12.

4.4.3 TT Boiler Fuel (Coal) Control Loop for Ball and Tube Mill (Figs. 8.13 and 8.14) In order to understand the loop for this type of loop, it is better to understand the operation and flow diagram for this type of mill, as discussed in clause no. 5.3 of this chapter. In fact, discussions on this loop are more relevant in clause no. 5.3, but are discussed here so that the reader can get options for various kinds of fuel flow control loops. A short discussion on the operation principle of the mill is also included in clause no. 5.3. Its worth noting that in this kind of mill, for proper performance of the mill, the coal-air ratio is very important—a

FIG. 8.12 Fuel flow control—tangential tilt boiler (bowl mill).

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typical such value could be 1.4–1.5. Typically, for a 100 t/h mill, the diameter is around >4.5 m and length is
¼7.2 m. This large-volume, slow-speed mill normally feeds two elevations in the TT boiler. Normally, a level inside the mill is maintained by controlling the feeder speed. It is to be noted that in this mill, instead of feeder speed, the PA flow is regulated to control the coal flow through the mill. Now, the net total coal demand generated in Fig. 8.11 has to be balanced with the actual coal flow. For ball and tube mill feeder speed controls, a desired coal level in the mill and not coal flow directly. In the furnace, coal burns to release energy for the boiler so that steam is produced. Thus, the energy released by the boiler at any instant of time is proportional to the steam flow and to the total fuel/coal flow (ignoring HFO; it actually acts as supporting fuel for flame stabilizing). Therefore, the boiler load can be considered proportional to the actual coal flow. The boiler load can be any one from: 1. Steam flow from boiler. 2. Turbine wheel chamber pressure or generator load. However, in a plant with partial HPBP operation, the steam flow in the HPBP line needs to be summed up with any of the above parameters for boiler load computation.

FIG. 8.13 Fuel flow control—tangential tilt boiler (tube mill).

FIG. 8.14 Mill air flow for ball and tube mill.

Boiler Control System Chapter

All the parameters just listed are very true as far as the kinetic energy for OT boilers. For drum boilers, the drum acts as a source of static energy, and for any change in energy release from the boiler, this also participates in releasing energy. Therefore, the rate of change of the drum pressure needs to be summed up with the parameters discussed in 1 and 2 above. These are very distinctly shown in Fig. 8.13. For more precision, the fuel computation from the energy released signals and the energy supplied by the supporting fuel is subtracted from the total energy released. As discussed earlier, in each side of the mill, the PA flow through the mill changes the coal flow and is functionally related to the coal flow in that side. The sum total of these signals forms a signal for total coal flow, as shown in Figs. 8.13 and 8.14. The total coal flow, thus computed, is compared with the net coal demand to generate the error signal for the PI controller. Immediately after the controller, the master A/M station provides the facility of common manual operation also. The final coal demand at the output of the A/M station (for both auto as well as common manual) is adjusted for gain depending on the numbers of sides of mills in auto. Thus, the load demand (in other words, the position demand for the damper in the PA flow through the mill) for each side of each mill is generated, as shown in Fig. 8.13. It then goes to the individual damper through its own A/M station to facilitate individual manual operation as well as adding bias. The output of each of these A/M stations drives the PA flow through the mill damper with the help of a pneumatic power cylinder to attend the desired position.

4.4.4 Mill PA Flow For Ball and Tube Mill (Figs. 8.13 and 8.14) PA flow controls are discussed in subsequent sections; however, to have a better idea, the PA flow loop for ball and tube mills in TT boilers are included here. The total PA flow and the bypass PA flow to each side of each mill are measured. The total PA flow and the bypass air flow to each mill have characterized variations as per mill load (each side). These are shown graphically in Fig. 8.14. Initially, each side bypass air flow is kept higher to dry and then take away the coal dust from the incoming coal and finally to mix with the PA flow through the mill to carry the coal to the boiler. Also, during the initial period, bypass air flow helps in gaining the velocity. As the PA flow through the mill increases with the mill load, the bypass air flow decreases as velocity boosting and heating is achieved by the PA flow through the mill. Normally, even at the highest load, the bypass air flow is kept open to, say, 10% so as to drive out the coal dust from the mixing box as well as have some drying effect on the incoming coal. The PA flow at each side of the mill is measured and characterized for comparison with the mill load signal generated in Fig. 8.13. The error thus generated is fed to the PI

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controller PA FLOW THROUGH MILL damper position so that regulated quantity of coal goes out to the boiler. As stated earlier, the bypass air flow maintains a particular characteristic with the total air flow, so the characterized total air flow signal is used as a set point for the bypass air flow damper control. The set point is compared with the actual bypass air flow to drive the P + I controller to generate the demand for the bypass air flow damper position. To make the loop more responsive, the function of total air flow control is added to the controller output as a feed forward signal.

5 COAL MILL CONTROL—MILL AIR FLOW CONTROL (FOR TT BOILER) General

5.1

General

There are two main modulating control systems associated with mills: mill air flow control and mill temperature control. Mill temperature control was covered in clause no. 5.2 of this chapter. Mill air flow controls in opposedfired and front-fired boilers based on Babcock designs are well covered in Section 4 of this chapter. Therefore, the mill air flow controls for the TT boiler (bowl mill) only are discussed in this section. Mill air flow controls for tube mills are covered in clause no. 4.4.3 of clause no. 4 and clause no. 5.3 of this chapter. Other control loops associated with tube mills are covered in clause no. 5.3. PA (sourced by PA fans) before and after APH forms cold/tempering air (CA) and hot PA (HA), respectively. One set of these air lines is mixed before entering each mill through regulating dampers called hot air dampers (HADs) for hot PA and CADs for cold PA. As the mill load is increased by changing the feeder speed, naturally the PA flow through the mill has to be increased so that more coal is flown to the furnace; otherwise, there may be jamming. The mill outlet temperature is maintained within a temperature band, so that the coal is dried enough to be ignited instantaneously in the furnace. At the same time, it is not too high so that there is a chance of fire. Exactly for these reasons, both dampers are used. In older days, the controls of bowl mill cross-operation of HAD and CAD were in use to regulate both the air flow and mill temperature control. This cross operation showed poor performance due to excessive cross interference, and hence the necessity of two independent loops was felt. As such, it is very difficult to maintain the desired temperature at the mill outlet during cold weather or the rainy season due to wet coal. In modern philosophy, for PA flow change due to load change is catered to by HAD if due to this by chance temperature increases then only CAD is modulated to regulate Mill outlet temperature. To be specific, the PA flow to the mill is regulated by HAD and the temperature is regulated by CAD independently with protection interlocks.

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5.1.1 Objective The objective is to ensure the required quantity of PA flow through the mill so that the exact quantity of coal demand from the particular mill can be catered to at all varying load conditions without any mill jamming. The relative dispositions of these dampers and the flow element are shown in Fig. III/9.2–4, PA flow P and ID. The entire quantity of PA demand for the mill initially is catered to by hot PA to avoid low temperature. However, during summer and dry seasons, the mill outlet temperature may rise. The CAD then opens to increase the cold air flow, causing the PA flow to increase than demand (set point) from feeder speed controller; PA flow controller then corrects its output to lower HAD opening. Cross operation of the two dampers takes place through the process, but not in the loop. However, as a precautionary measure, an interlock has been incorporated to see that when the CAD is in manual or the temperature is too high, the HAD loop goes to manual so as to avoid any chances of a high mill outlet temperature.

5.1.2 Description (Fig. 8.15) The PA flow to the mill is measured after mixing the HA and CA with the help of a Ventury/Pitot/Piccolo tube, redundant smart DPTs, and suitable temperature compensation arrangements, as shown. The final set value is taken after the “MAX” selector having one manual set input and another being derived proportional value from feeder speed so that PA flow never becomes less than that required for corresponding feeder speed. In fact, to clear out any mill jamming, the operator can set a value other than that required for the corresponding feeder speed. The error signal generated by the difference between the set and measured values is fed to the controller. At the output of the controller, the feeder speed demand has been added as the feed forward signal, so that in case of any load change, the PA flow can act fast. Finally, the output of the controller through the A/M station goes to the FCE of the HAD to regulate the same.

5.1.3 Alarm and Interlock 1. Alarm: a. The PA flow to the mill low is generated through the LVM. A spurious alarm during start-up is prevented by ANDing it with HAD/CAD in auto. b. When CAD is in manual or high mill outlet temperature, an alarm is generated. 2. Interlock: a. When CAD is in manual or high mill outlet temperature, this trips the loop operation to manual. b. If the high temperature persists over a time period after operator action, the opening command to HAD is blocked. c. Released to auto needs permission from FSSS/BMS.

d. CAD and HAD not in auto blocks input and output to/ from the controller to avoid saturation.

5.2

Mill Temperature Control

General Mill temperature control is an essential part so far as coal or pulverized fuel combustion is concerned. This is a vital control in consideration with the following points: (i) The coal while getting out of the pulverizer must be dry to avoid moisture (due to weather and other seasonal changes) vis-a-vis clogging up the coal pipe lines leading toward the furnace chamber. (ii) Coal types normally used in power plants are required to be preheated to make them more easily combustible. (iii) The appropriate extent of coal drying calls for lower pulverizer start-up costs. Considering the above, the only way out is to maintain a fixed set point at a higher value capable of providing a sufficient margin to handle spikes in surface moisture.

5.2.1 Objective The purpose of the mill temperature control is to supply fuel at an optimum temperature. By optimum, this means it should be higher than to maintain flowability and less than to avoid fire hazards. For this purpose, the transportation media, that is, the primary air inlet temperature to the mill, is considered the heating agent with a sufficient higher value of temperature and quantity so as to raise the mill outlet temperature, the measured/process variable of this control strategy.

5.2.2 Discussion The mill outlet temperature is maintained at a set value by introducing preheated primary air (PA) into the mill’s inlet. The supply of the right quantity of PA is equally important so as to ensure sufficient heat input, which would be exchanged through direct mixing with the solid but pulverized fuel. For obvious reasons, the amount of air would ultimately be proportional to the mill load in relation to the fuel or total air/main steam flow, as per the control strategy. For each mill, one set of hot PA dampers and another set of cold PA dampers are provided as the FCEs with various types of operations to suit plant design. In the early days, the hot PA and cold PA dampers were regulated in the same direction when there was a change in PA flow demand; on the other hand, they were supposed to move in the opposite direction to respond to the change in mill outlet temperature. According to some other schools of thought, the feeder speed controller output, after getting the command from the boiler fuel demand, is transmitted to the coal feeder speed changing system and to the position

Boiler Control System Chapter

FIG. 8.15 Mill air flow control—for bowl mill TT boiler.

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controller of the hot PA damper. This arrangement envisages simultaneous control actions in speed changing and repositioning of the HAD. The primary duty ascribed to this hot PA damper, according to this control strategy, is to maintain only the mill outlet temperature to a desired value and also to take care of the above feeder speed demand as a feed forward signal for damper position control. The function of the CAD position controller on the other hand is to control the total primary air flow to a value required to maintain the flow velocity for safe and smooth transport of the pulverized fuel to the furnace for combustion. The demand signal for the cold PA damper may be generated directly from the boiler load demand after the lead-lag route; the same signal also acts as a process trim on the feed forward control applied by the hot damper controller. There may be some modification where the HAD gets a feed forward signal from the PA flow controller also, and the CAD controller gets a feed forward signal from both the fuel and temperature controller. Unfortunately, the control action was not so effective due to its sluggish response frittering away excessive time. This resulted in undesirable disturbances in the steam pressure whenever the boiler load or fuel quantity changes are called for. The control loop considered for discussion in this section is of a typical 250 MW plant with a Babcock design where the PA flow to each mill is determined by a separate (refer to fuel flow control) damper after these two flow paths (hot and cold PA) are adjoined, that is, in the common line. The hot and cold PA damper set is dedicated to temperature control only. For no temperature change due to load change, these dampers would not respond to the new flow requirement. However, the PA fan inlet dampers would come into the picture to take care of the new load by maintaining the PA header pressure. Hot and tempering air mixing requirements vary as the fuel moisture varies and as the primary air bias varies. A mill outlet temperature control system nowadays is so properly set up that its activity cannot even temporarily influence any impact in the PA flow.

5.2.3 Control Loop Description (Fig. 8.16) The control loop philosophies are of various types as discussed in the above section and may vary with the manufacturer’s special design and type of fuel, to some extent. As there is a separate section dedicated to the control loop for ball tube mills, this section will cover the control loop of other types of mills also. 5.2.3.1 Measurement of Mill Outlet Temperature The temperature (measured variable) signals, after a sufficient (triple) redundancy and voting circuit, is transmitted to the controller.

5.2.3.2 Mill Outlet Temperature Control Among the many control strategies to choose from, the selected loop as described in this subsection is a part of the total PA system that takes care of the temperature control, only without taking any notice of the other parameters and effects. As described elsewhere in this section, the mill-wise PA flow is hooked up with the fuel flow control by the PA to mill damper. Mill-wise hot air and CADs are provided to maintain the mill outlet temperature. The total impact of all the mill-wise PA flow and mill outlet temperature controls on the actual total PA flow is taken care of by the PAF inlet dampers by maintaining the PA header pressure. This control loop strategy is the most noninteractive between the PA flow and temperature, where both parameters are very important to assist the optimum transportation condition of the pulverized fuel. The controller is set with a fixed desirable value for the mill outlet temperature and simultaneous action of HADs and CADs (CSAD) is contemplated in this control loop to maintain the temperature. The normal operating zone envisioned a full open condition of HAD and any temperature change is taken care of by the CAD. With HAD full open, the CAD modulates from the full closed position up to almost a 60% (typical value) opening. At 60% of the CAD position, if the mill outlet temperature increases, the controller output would call for a further opening signal to the CAD and simultaneously a decreasing signal to the HAD. This operating zone of simultaneous positioning of the two dampers is very limited. If the temperature still increases, there would be a certain point where the CAD would attain and remain in full open position and any further increase in temperature would be taken care of by the HAD. The situation would be just the reverse when the temperature starts decreasing to such a value when H the AD position would be increasing toward 60% (typical value) and then the CAD position starts decreasing. After a certain time, the HAD would again be at the full open condition while the CAD would modulate. A further scope is envisioned in maintaining the mill outlet temperature if it goes beyond the capabilities of the above two dampers when the air temperature itself decreases at the outlet of the PA heater, due to low flue gas temperature resulting in poor heat exchange. The sole cause in that event being the flue gas heat content, some measures have been adopted to prevent it from falling across the heat exchangers, instead bypassing a part of the heat exchangers in the superheater/reheater section of the boiler. This is accomplished by providing another common temperature controller. The measured or process variables are the same mill outlet temperatures, but through a minimum selector and of those mills whose controllers are running on auto mode only. The set point is derived after putting a negative bias on the previously mentioned set point of the main mill outlet temperature control. This set point being lower, its controller output would not normally interfere with the main control

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FIG. 8.16 Mill outlet temperature control.

system. Under the situation when the mill outlet temperature decreases, even by fully closing the CAD and fully opening the HAD, below the bias value, the second controller would take the charge of the affair and transmit the output command to the bypass dampers to take proportionate bypass position so as to allow a part of flue gas to flow bypassing the heat exchanger. The average flue gas temperature now being more than that without the bypass, it would then assist raising the mill outlet temperature with a higher PA temperature at the PA heater outlet.

5.2.4 Mill Outlet Temperature for TT Boiler (Fig. 8.17) The control loop for the mill outlet temperature discussed here is mainly meant for TT boilers based on a CE design with a bowl mill. The control loop for the ball and tube mill is discussed separately in the next section. Fig. 8.17 may be read in conjunction with Fig. 8.15 and the associated P&ID Fig. 3.36.

1. Objective: To regulate the mill outlet temperature at the desired point so that the coal delivered from the mill is completely dry with the desired temperature. Also, in case of high mill outlet temperature, cold air is blown to avert a high-temperature fire hazard. 2. Discussions: Normally/initially entire requirement of PA flow necessary for a particular load at mill is tried to achieve through HAD enabling complete drying of the coal (especially during monsoon season) and to raise the mill temperature as desired. However, there may be eventualities during a hot/dry summer where the mill outlet temperature shoots up, which is an undesirable situation toward a fire hazard. Therefore, the CAD comes into operation whenever there is a need to bring down the mill temperature. Naturally, when this damper operates, that is, starts opening through process feedback, the HAD will close. So here also there is a cross operation of the two dampers but through a process. Additional arrangements of mill inerting systems with inert gases such as N2, CO2, etc., need

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(A)

FIG. 8.17 Mill outlet temperature control for bowl mill and tube mill.

(B)

Boiler Control System Chapter

to be kept (reducing the air supply is also an aim). This is more important for ball and tube mills, especially when they are operating with one side only. 3. Descriptions: Mill outlet temperatures are measured by redundant temperature elements and transmitters are put in an error generator. The output of the error generator drives a PID controller. In general, with temperature being a sluggish parameter, it is always advisable to use PID controllers for better results. To prevent controller saturations, the controllers are put into service only when both the loops are in auto. The output of the controller through the I/P converters normally drives the pneumatic actuators meant for the CAD. 4. Interlock: a. As stated earlier, only when both HAD and CAD are in auto will the controller be put into operation. b. Because FSSS operations depend on mill temperature conditions, with the help of a limit value monitor (LVM), the necessary contact statuses have been shared with FSSS. c. The loop can be released to auto from the FSSS command. d. As protection, the full opening command as well as the > x% command for the mill CAD are issued from the FSSS so that there is sufficient cold air circulated. e. Whenever the auto release command from the FSSS is missing or the HAD is in manual, it is necessary to inhibit auto operation so that the operator puts all attention on the mill outlet temperature. f. That will be the check-back signal for FSSS from the loop for the damper position.

5.3

Mill Control (Ball-Tube Mill) (Fig. 8.18)

General The ball tube mill is one of the many types of mills/pulverizers used for grinding different types of fuels such as coal or other minerals such as cement plant ingredients, etc. A ball tube mill basically includes a large, hollow cylindrical drum that rotates along its axis, supported by a trunnion on each end. Wear-resistant liners are provided inside the drum, which contains different sizes of balls filled up to half of the drum. These balls are normally made of cast alloy steel or forged steel, and have sizes varying from 25 to 150 mm or perhaps more for higher-capacity mills. The drum is made to rotate at a slower speed by standard high speed electric drives through a gear train consisting of a reduction gear box and large spur gear. The slow speed is normally available in the range of 13–35 rpm, depending on the size of the drum and specifically the diameter of the drum. During drum rotation, all the balls move upward to about 60%–70% along the periphery and then cascade over each other with a tendency to move toward the center of the drum as a continuous process. This forces a mass of

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balls and higher-sized materials to mix with each other at the bottom of the drum, resulting in material size (around 25 mm) reduced to small particles. The reasons behind this action may be attributed to the following forces: (i) Impact of the falling heavy balls causes cracking of the materials. (ii) Attrition of materials with each other and with liners. (iii) Crushing of the heavy balls rolling over each other and liners with the materials in between. Very high coal fineness is achievable in the range of 70–90 mm at the outlet. Raw materials are introduced from both ends of the drum through variable speed feeders so as to regulate the PF flow as required. An adequately heated PA is blown, through the hollow shaft of the screw feeder inside the pulverizing zone of the mill, for drying the materials; pulverized fuel (PF) is then made fine and light enough to become airborne and is vented out of the pulverizing zone from both sides of the drum to the combustion chamber. An external classifier is provided at both sides of the drum so as to allow only the fine particles to go outside. Due to the whirling action, larger particles experience more kinetic force and collide with the classifier wall, only to lose the force to zero. Then, this rejected material comes back downward for force due to gravity to the grinding zone with the raw feed. The new raw feed continuously enters through the ends of the drum to assume the already-vacated place of the departing airborne particles. For this type of arrangement, a half-mill/one-side operation for partial loads is possible and is done in practice for a short time only, as this operation may result in high temperature and accumulation of pulverized fuel in the unused classifier side, causing an explosion. The classifier should be so designed as to ensure the removal of fine feed particles from the grinding zone so that the production of extreme fines is eliminated and mill current in relation to power consumption is kept within limits. The relatively large quantity of raw feed and semiground feed mixture in the grinding zone may actually be regarded as the additional storage, which can cope with any unexpected and abrupt increase in the demand. However, it is to be noted that the electrical power consumed for a particular quantity of raw feed of this type of mill is very high, especially at the partial load. There is the possibility of clogging at the feeding end of the pipe for the presence of moisture in the surface of raw feed, which may in turn reduce the capacity of the mill. It is therefore very important to reduce the moisture content in the raw feed. However, the arrangement of recirculating the heated and dried oversized rejects helps in reducing the moisture and thereby the clogging at the feed inlet. The hot air with powdered fuel flows out of the mill through the annular portion of the screw conveyer or feeder and the

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FIG. 8.18 Schematic diagram of ball-tube internal arrangements.

trunnion tube and thereby dries the raw feed while approaching the screw feeder. During the starting period, a portion of the hot PA is bypassed and sent through the raw feed to minimize the moisture in the raw feed. As the load increases, this bypass air is decreased and finally brought to zero above a particular load. However, according to another school of thought, the bypass damper is kept open to a minimum value, say 10% or even up to 100% mill load, so that even at a high load, the fine feed dust is not unnecessarily fed to the mill, increasing the mill current. When the mill trips, a good quantity of heat trapped in the mill is lost. A good inerting arrangement of the mill may be necessary to eliminate fire hazards. A trunnion seal is provided between the rotating drum and the related stationary components such as the raw feed piping system so that the material can move to the rotating drum end. The trunnion seal assists the passage of raw feed toward the rotating drum but, on the other hand, it prevents the escape of material into the surroundings. It is always desirable to form the best possible seal between the stationary and rotating components to thwart the tendency of the fine particles to escape. Replacing the trunnion seals is a cumbersome job that requires removing the inlet/outlet box from the foundation blocks under the trunnions and the downtime toward the same is significant. However, a sealing arrangement is provided by supplying pressurized air through separate seal air fans in an arrangement of common redundant fans or an individual fan. Ball tube mills are not suitable for intermittent operation as the significant amount of heat energy stored in both the

raw feed, particularly the coal and the balls, may lead to overheating and fires when the mill is kept idle. As per the operating principle and functional requirement of the mill, the noise level is significantly high and requires noise-suppressing arrangements.

5.3.1 Objective of the Control Strategies (Figs. 8.19–8.21) There are a few control loops for the safe and efficient running of mills. Fuel flow and PA flow control details for ball and tube mills have already been presented in Section 4 of this chapter (Figs. 8.13 and 8.14). The first and most important one is the mill outlet temperature control. It is provided to supply the fuels at an optimum temperature for various reasons, the same as the other mills described earlier. During start-up, the moisture and temperature are controlled by diverting a portion of the hot air between the feed pipe and classifier, and the control of this part is taken care of in the temperature control of the PA flow to the mill. (i) In some plants, the PA inlet pressure control loop is provided to maintain the common PA fan discharge header pressure before the primary air heater and the take-off point of the cold PA header for the cold PA system (PA fan suction may be from the atmosphere or FD fan discharge). Mixing of hot PA (taken after the primary air heater) and cold PA is done for controlled temperature for each individual mill. Though not shown in the above drawing, the PA header pressure control loop assists the

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FIG. 8.19 Typical flow and control diagram of ball tube mill with common PA fan system.

FIG. 8.20 Typical flow and control diagram of ball tube mill with individual PA fan system.

smooth and bumpless control of the actual PA flow to the mill accomplished by the PA to mill damper control. The PA pressure control may not be required when the millwise PA fan suction is taken from the temperature-

controlled, individual hot PA header for a hot PA system (cold and hot PA headers are taken from the FD discharge before and after the common air heater, respectively, without a separate PA heater).

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FIG. 8.21 Typical flow and control diagram of ball tube mill with common PA flow control.

(ii) The mill drum level control loop (Fig. 8.22) is meant for maintaining the level of the charges inside the drum. This control is achieved by sensing the load on the mill by measuring the differential pressure across the mill or the characteristic sound produced by the mill at different feed levels. The set point is normally a fixed value and the controller output is used to regulate the speed of the solid fuel feeder, so as to maintain an appreciable fuel reserve through an assured level in varying load. On account of ambient sound, sonar transducers are used as corrective or confirmatory elements and not as a prime element to measure the level. Mill load or fuel flow control is to follow the demand from the boiler master demand control signal and, unlike the bowl mill, this is achieved by regulating the quantity of the transporting agent, that is, the PA flow. The control strategies may be of different types as indicated below: (a) Control of individual PA dampers with common PA fans. (b) Control of individual PA fans through PA inlet vane/ damper control. (c) Control of individual PA fan speed through VFD. The details are provided in clause no. 5.3.4.4 of this section and clause no. 4.4.3 of Section 4 of this chapter in conjunction with Fig. 8.13.

(iii) Differential seal air pressure control is achieved by regulating the seal air damper position through a controller with transmitters sensing the differential pressure across the mill air inlet and mill drum. Seal air to mill inlet pressure is varied to ensure some extra pressure to arrest the dusty air escaping the mill. A control loop for this purpose may be common for two sides of a mill or may be individual for each feeder, as dictated by the milling system.

5.3.2 Discussion 5.3.2.1

Mill Outlet Temperature Control

The basic mill temperature control loop has been discussed in clause no. 5.2 of this chapter. For ball tube mills, there is another consideration for addressing the problem of moisture in the raw feed before entrance to the mill inside. In fact, during start-up, the amount of hot PA is less and may not be sufficient to prepare the feed in the right condition for proper grinding and flowability. This untoward situation is eliminated by increasing the temperature of the raw feed at the mill inlet by introducing hot PA into the classifier (mixing chamber), between the raw material feeder and the mill inlet through a bypass damper in the PA to mill line. This additional hot air

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(A)

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(B)

FIG. 8.22 Ball tube mill level control.

preheats the feed and reduces the moisture content. This arrangement is mainly operational during start-up, but may continue up to a certain load and even up to a full load, depending on the concerned mill design. Although this appears to be a part of the mill temperature control, this initial control part is accommodated in the mill load control, that is, a part of the PA flow to the mill control, as depicted in Figs. 8.23 and 8.24.

amount of load is fed by the reserve capacity before the feeder response takes place. The shortfall of materials in that case is detected by the low level and the feeder then responds accordingly. However, there may be a feed forward signal from the PA flow to correct the feeder speed. This control is achieved by sensing the load on the mill by measuring differential pressure across the mill or the characteristic sound, which is also called the electric eye, produced by the mill at different levels.

5.3.3 Mill Drum Level Control Loop As mentioned earlier, the mill drum level control loop is meant for maintaining the level of the charges in the side the drum. In this type of mill, the capacity of the raw feed storage is very high and is maintained at an average constant value by means of a level control of the charges, irrespective of actual fuel flow. The advantage of the availability of a constant amount of material at all loads is the reserve fuel, and this is highly favorable for the process control, especially when there is a sudden load increase. The extra

5.3.3.1

Mill Drum Level Sound Detector

It has been observed that the sound or noise level of a mill, as generated during the normal range of operation, changes in accordance with the magnitude of the mill loading. Elaborate experiments have revealed that character of sound as well as its intensity are different, even when a mill is grinding a single material, under the operating condition of running wet or dry, in open or closed system without bearing any relation whether producing a coarse or fine

FIG. 8.23 Fuel flow control for ball tube mill (by PA Damper).

FIG. 8.24 Fuel flow control for ball tube mill (by Vane or speed control).

Boiler Control System Chapter

product or actual real time feed rate. For example, the sound intensity is going to be more as the drum charge level becomes less; on the other hand, as the charge becomes more, the sound intensity is going to be less and will turn out to be practically indistinct to the ears, that is, less than the exact sense of hearing of a human operator. Automatic control of ball tube mills utilizes this sound property as the controlling variable. It has been proved to be a highly convenient, realistic, and dependable solution with economical sanction. By installing a microphone that is duly suitable for the range of frequency generated and proficiently utilizing the energy output of the detector to control the raw feed to mills and thereby maintaining the grinding efficiency at a its maximum level. The acoustic detection device is installed in a kind of parabolic reflector to permit the sensor to pick up the signal generated by only one mill at a time. The raw and low-level electrical signal output of the acoustic detector is then amplified and modified in an electronic transmitter to make it suitable for use in an automatic control loop. The detection system as a whole is calibrated to measure the optimum sound level predicting the mill charge level and the control loop strategy is built toward maintaining that level at a constant value by adjusting the speed of the raw feeder, allowing more or less material to the mill.

5.3.4 Control Loop Description 5.3.4.1 Mill Outlet Temperature Control The control loop is similar to that discussed in Sections 5.2.3.1 and 5.2.3.2. The relevant drawings are Fig. 8.16.

5.3.4.2

PA Inlet Pressure Control Loop

As already discussed, this control loop is provided to maintain the PA header pressure before the mixing of hot and cold PA duly controlled for temperature. Fig. 8.10 is also applicable for this type of mill when the PA is common to all the mills. This control loop will not be applicable for individual PA fan systems where mixing is done before (hot PA system). For a control loop description, Section 4.3.2.3 of this chapter may be referred. Common PA fans are provided with suction normally from the atmosphere or maybe from the FD discharge header. The header pressure control system is done through different types of FCEs. As the fuel/load control is solely done by the position adjustments of the PA damper near the mill, this control loop assists the smooth and bumpless control of the fuel flow transported by the PA flow to the mill as the upstream PA header pressure control takes the responsibility of providing an adequate quantity of air at any environmental condition without sacrificing the required downstream pressure.

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5.3.4.3 Mill Drum Level Control Loop Fig. 8.22 depicts the simple control loop. Any of the mill differential pressure transmitters or level (sound detector) transmitters is selected and the selected signal is connected to the controller as the process or measured variables against a fixed level set point. Sufficient redundancy in measurement may vary as per the plant’s operating philosophy. The controller output is utilized for adjustment of feeder speed with the help of a VFD or SCR control for a gravimetric feeder/feeder speed variator. At the higher load, the charge level inside the drum would decrease and the feeder speed should increase accordingly to replenish the material. For a decreasing load, the reverse action would take place. To take care of the sudden load change, the deviation between the characterized PA flow and the DP across the mill is used to modify the controller output to achieve the desired mill charge level. 5.3.4.4

Fuel Flow Control Loop

Mill load or fuel flow control is to follow the fuel demand from the boiler master demand control signal. and is achieved by regulating the quantity of PA that is the transporting agent only. Fig. 8.23, respectively, depict the functioning of the control loop, which is almost similar to that of other types of mills. For other mills, the fuel demand signal from the boiler master demand is first taken care of by the mill-wise PA flow control system if the demand is less than the prevailing air flow control system. The characterized PA flow is then construed as the feeder speed demand. The tube mill control system, on the other hand, envisages feeder speed control for maintaining the mill level control only and so the fuel flow control is achieved through control of the feeder-wise PA flow to the mill itself. However, the feeder-wise PA flow as measured after redundant transmitter voting selection and density compensated through temperature correction is again characterized to get equivalent fuel flow. The total fuel flow is then computed by summating all the fuel (PF) flow of the running feeders and the supporting fuel (oil or gas), if any is being utilized at that time with proper weightage, taking consideration of their thermal or calorific value. The higher selection of this total equivalent fuel flow signal and the air flow demand signal from the boiler master demand (Fig. 8.2) is then taken as the actual air demand, just like other types of mills. As already discussed in Section 5.2.3.2 (Mill outlet temperature control) of this chapter, there is another feeder-wise control system associated with fuel flow control, known as the bypass damper control. This feeder-wise damper is provided for each mill end for preheating the raw feed, which is an essential requirement during the start-up period. No process measurement signal is utilized in this subloop.

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The same fuel demand from the boiler master demand (Fig. 8.2) is also taken as the set point for the position demand of the bypass damper as shown (Figs. 8.23 and 8.24) in the control strategy and the graphical representation of approximate positions of the two FCEs. The abovementioned two position demands operate in the opposite direction. After being fully open for certain loads, ensuring the elimination of initial moisture, this bypass damper would begin to close gradually as the load increases. There are two main types of fuel flow controls achieved through the proportionate PA flow only: (i) Common PA fans with individual PA dampers. (ii) Individual PA fans with vane or speed control. Common PA fans with individual PA dampers (Figs. 8.19 and 8.23) Here, the mill PA flow and bypass PA flows are combined to form a total mill-wise PA flow to the furnace. The boiler master demand acts as a set point here where the mill-wise PA flow is the measured value, as this air flow is only responsible for transporting the fuel to the furnace. The controller output is the demand signal for the individual PA damper. For bypass dampers, the boiler master demand is characterized to generate the set point while the actual position of this damper acts as the measured value for the controller, the output of which is the demand signal for the bypass damper. For any load change, the two flows would readjust their positions to deliver the required PA flow. For a higher load, the bypass damper would tend to close to allow less flow for preheating the raw feed and the PA damper to the mill would open more to take care of the load demand. Individual PA fans with vane or speed control (Figs. 8.20 and 8.24) Here, the bypass PA flows need to be subtracted from the total mill-wise PA flow for the fuel flow control, and the total mill-wise PA flow to the furnace is required for air flow control. The reason is the FCE and the flow element are both located in the common primary air path to the individual mill. The boiler master demand acts as a set point here where the PA flow to the mill is the measured value. The controller output is the demand signal for the individual PA vane or the variable speed drive. For the rest of the control loops, that is, for the bypass damper, the control strategy is the same as the previous one described above. Mill-wise PA flow control common to both sides (Fig. 8.21). This type of mill design vis-a-vis operation is somewhat different from other types as discussed earlier; it is mainly followed by manufacturers such as M/s Foster Wheelers Energy Corporation. Here, the boiler combustion control signal regulates the output of the mill by the primary air (PA) flow control damper placed in the common line to both the ends or sides. The predrying of the coal feed is done at

the entry of each side before entering the drum, unlike what is done by the bypass PA damper in many types of tube mills. Another significant difference is the provision of an auxiliary air and purge air supply line taken from the cold PA for each side of the mill drum. The same is designed to the required minimum velocities of PA/fuel mixture for maintaining proper flowability inside the coal duct and preventing fuel settling during start-up or extreme low load operation. This feature extends the individual mill load range without encountering drifting or pulsating fuel flow to the burners. The other purpose is to purge the coal air line automatically when the burners are taken out of service. The feed level control in the drum, the classifier outlet temperature control, and the seal air DP control are very similar to other types of mills, with the exception of the source of seal air. Here, the seal air supply is taken from the cold PA without any provision for a seal air fan.

6 FURNACE DRAFT CONTROL General The furnace draft control loop is very important in the boiler control system. The boiler has two distinct zones of functional operation: the firing zone and the heat exchanger zone. The firing zone, along with water walls (to insulate the heat content from around the side and top walls), is normally described as the furnace. The pressure of the top portion of such a furnace is generally maintained at below atmospheric pressure that is, a 3 to 5 mm water column. This task is accomplished with the help of induced draft (ID) fans, which evacuate the products of combustion, that is, the combination of different gases from the furnace. By furnace draft control at such a typical pressure value implicates so many things that is quite surprising. The low but near to the atmospheric value ensures that neither explosion nor implosion takes place. It is known that an explosion in the furnace occurs when the rate of volume of flue gases or the products of combustion increase abruptly as a follow-up action of introducing a huge quantity of fuel and air. The situation causes instantaneous volume boosting at a much higher temperature as a result of exothermic reaction. With the furnace volume and the wall thickness being fixed and limited, the increased gas volume, if it goes beyond the design limit, may cause an explosion. The near atmospheric pressure is not only safe from an explosion, but it also prevents the possibility of implosion, a situation that may arise due to a sudden collapse of flames, as discussed in Section 6.2 of this chapter. The advantages are safety against explosion/implosion, less wall thickness, fewer operation hazards and less of a possibility of leaking flame or hot flue gas, which means less heat loss and pollution. The ID fans are normally supplied with inlet vanes for controlling the amount of volumetric flow handled by the fans. The control loop selected for the discussion of the

Boiler Control System Chapter

furnace draft control in this section is a typical 250 MW thermal power plant with ID fans with an additional mechanism, that is, a hydraulic coupling along with a scoop tube control for varying the speed of the fan. In fact, any one of the above items is sufficient to administer the control system as the FCE, but the present loop may be quite interesting as to how the things are taken care of by the two devices mainly for higher MW plants to achieve better and smoother controls.

6.1

Objective

The furnace pressure is maintained at a negative pressure and hence is popularly known as the furnace draft. The main objective of this control loop is to achieve the desired pressure at all loads by sucking the appropriate amount of flue gases, nonparticipating gases in the combustion process, and unburnt fuels (if any). The ID fans are provided to perform the duty with a necessary arrangement to have controllability, which acts as the FCE of this important loop. These control accessories are made to open (or increase) and close (or decrease) to suck the required amount of flue gases so that the furnace draft is maintained.

6.2

Discussion

Furnace draft control is a comparatively simple loop, considering the other control loops in a thermal power plant. However, with the furnace itself being a huge voluminous part of the boiler handling the burning of fuels, the safety implications are to be taken care of with due importance and significance. The applicable codes and standards must be followed to avoid any untoward situations while taking up the design aspects of the furnace-related equipment. The National Fire Protection Association (NFPA) codes provide the guidelines that one must read and follow before realization of anything regarding furnace application. The most relevant code is the NFPA 85: Boiler and Combustion Systems Hazards Code, which includes the protection measures to be taken to prevent fire or furnace explosion/implosion. The NFPA also stipulates some additional interlocks for incorporation into the furnace draft control loop so that the required operating safety margins are ensured. For example, the interlocking signal from high and low furnace pressures is to be utilized to block the FCEs from further repositioning, which may further jeopardize the furnace condition. Another important example of interlock, as per the NFPA codes, is taken from the master fuel trip (MFT) logic signal actuated from the dangerous condition that causes the emergency shutdown of the boiler. On the occurrence of such a sudden event, the flame within the furnace collapses violently, with all types of fuels completely and abruptly removed. This state of affairs invites a very dangerous situation such as an implosion; it can also be the reason for severe wear and tear of different boiler parts. To obviate

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those circumstances, the interlock allows the controller output to keep the FCEs to attain a predefined fixed position for a definite period of time and then releases the device back to normal operation. Normally, the ID fan suction head is more than the negative pressure the furnace structure is designed to withstand in the case of any eventuality. The advantage of maintaining the furnace pressure at a constant value may be explained in another way. The Universal Law of Perfect Gas states that, PV ¼ MRT where for any system, P stands for absolute pressure, V for volume, M for mass of the substance within the volume considered, R for the universal gas constant, and T for absolute temperature. Considering the system as a whole, it is apparent that the volume V is also a constant value whereas the universal gas constant R is approximately constant, which means that P ¼ kMT (where k is a constant). The above equation shows that the product of M and T can be made constant if the furnace pressure (or the draft) is kept constant. As the furnace temperature depends on the boiler load, or in other words, the thermal energy balance (heat input and output), the mass inside the furnace is automatically kept adjusted by the ID fans by sucking the required amount of flue gas. At the time of MFT (when the fuel is immediately cut), the temperature of the furnace drops rapidly with a subsequent drop in pressure. Instead of flue gas, there would only be hot air to be sucked by the ID fans. The drop in furnace pressure would cause the ID fans to suck less gas as instructed by the furnace draft controller and the mass M within the furnace would improve such that the product MT again equals the constant furnace pressure P. The amount of hot air pushed by the FD fans under this condition may be different for different boiler manufacturer, but ID fans finally take care of the mass availability within the furnace under any condition so far as implosion of the furnace is concerned. The BMS also generates binary signals to enable the control system to run in automatic mode or the FCEs to attain a minimum position as per the demand of the prevailing situation.

6.3

Control Loop Description

See Figs. 8.25 and 8.26.

6.3.1 Measurement of Different Various Parameters 6.3.1.1

Furnace Pressure

The furnace pressure is measured by a differential transmitter with sufficient redundancy and at the appropriate location to get an average and representative measurement. For a larger furnace, there may be sets of transmitters at both the opposite walls for a better result. The span selection of a

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FIG. 8.25 Furnace draft control (inlet vane).

transmitter is very important; normally, these should not be too wide or narrow. Due to the fluctuating nature of the furnace pressure and dusty atmospheres, normally a special volume chamber is put for each transmitter for measurement purposes, as detailed in Fig. 12.13B. On account of the volume chamber, fluctuations are arrested and line choking is less as dust settles in the chamber. 6.3.1.2 ID Fan Inlet Vane Position These parameters, being the position of the FCEs, are measured as a standard procedure and also used in the control strategy for the ID fan speed control through the hydraulic scoop tube control (or VFD).

6.3.2 Different Control 6.3.2.1 Furnace Draft The furnace pressure signal is a very fast-changing parameter and may disturb the desired control action if

connected to the controller directly. To circumvent the situation, a LPF algorithm is utilized to eliminate the highfrequency components of the furnace pressure transmitter output and allow only the signal with a comparatively low frequency. The LPF output signal is taken as the measured/process variable whereas the set value to the controller is a fixed one. The total air flow acts as a feed forward signal after passing through a derivative function and is summated to the error signal between the measured and set values. In an alternative (ISA recommended) loop, the FD fan impeller/vane control demand signal acts as the feed forward signal and is added at the output of the controller for a similar function. Then, after the gain function is added to take care of the number of ID fans running on auto mode. The final error signal then becomes the input to the PID controller. The controller output has to pass through a maximum/minimum limit so that the inlet vanes do not

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explosive situation. For MFT due to both FD/ID tripping, vanes/dampers in the air and flue gas path would open slowly to full value to create a natural draft to ensure that the furnace does not go beyond design limits. (ii) The BMS issues the release to automatic control command signal upon checking relevant conditions congenial to auto control operation. (iii) The BMS also issues the commands to assume a minimum position at certain process conditions to prevent an implosion when the time period as described in point number (i) above is over. On a very negative furnace pressure signal also, the BMS binary signal output may be used as an interlocked condition that closes the ID inlet vane or decreases ID fan speed or blocks the increasing signal to prevent implosion.

FIG. 8.26 Furnace draft control (scoop tube).

reach the end positions, causing an untoward situation for furnace safety. Regarding fine tuning of the furnace controller, one should avoid the use of a very fast integral. It is a fact that furnace pressure changes at a very fast rate but not instantaneously; therefore the process being compressible fluid, the capacitance effect needs to be considered which incorporates the size of the furnace, the huge ductworks between the furnace and fans, etc. The inlet vanes assume the positions as per the controller output to maintain the furnace draft only, but they have got some other safety interlocked functions also. Those are indicated below as incorporated for a typical boiler, but they may be different to some extent as per the manufacturer’s recommendation. The safety features are: (i) The inlet vanes are forced to assume a certain preassigned open position (as dictated by the control strategy) for a certain time in case of MFT (other than FD or ID fans). This interlocking command enables the unburnt fuel, if any, to be evacuated to avert any

There are other interlocked operations that also recommend blocking of the closing signal of the ID fan inlet vanes from the binary signal set to actuate on the preset high furnace pressure. The reverse is the case for low furnace pressure, upon occurrence of which the binary signal would block the opening signal of the ID fan inlet vanes. The settings of all these signals are ascertained by the boiler and fan supplier during the design stage dictated by safe operation of the plant. The ID fans are equipped with another FCE called the scoop tube actuator, through the operation of which the speed of the ID fans can be varied and hence the suction capability can be enhanced or decreased. The scoop tube actuator, upon getting the modulating command, adjusts its position so as to allow more or less oil in a chamber to raise or lower the oil level. The oil chamber forms a part of the hydraulic coupling connected with the electric motor (Chapter 6, Section 3.1.4, Fig. 6.24) and the ID fan itself where the motor runs at a constant speed and the ID fan speed varies as per the oil level in relation tothe scoop tube position. In this control loop part (Fig. 8.26), the scoop tube actuators play a secondary role. Here, the scoop tube actuator is modulated so that the inlet vanes operate within certain maximum and minimum positions. The vane position signal forms an input of a maximum selector, which has another input set manually to represent the maximum limit position of the inlet vane. There is one summator having its one input (with + sign) from the above maximum selector output and anther input (with  sign) from the above-mentioned vane maximum limit position. So long as the vane is operated within the maximum limit, this limit signal is selected as the output and the summator is getting both signals of the same magnitude but of opposite signs to cancel each other for a zero output. Similar is the case for the minimum position of the vane and that summator output is also zero when the vane is operated at a position more than the minimum one as set manually. The above two summator outputs again act as inputs to

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another summator whose output acts as an error signal to the scoop tube controller; it would also be zero for the inlet vanes being operated within the set limits. In that case, the controller output would not be changed and so the speed of the ID fans allow the inlet vane to operate freely as per the furnace draft excursion. Now, the case is different for the situations when the vane crosses the maximum or minimum limit positions. For example, when the inlet vane position is more than the maximum limit, the excursion is positive and the difference in the signal forms the error signal (as the inlet vane position is more than the minimum position, the magnitude of the minus signal of the down most summator is zero). The controller output would be changed to attain the new position, which would enable the vane position to be brought back within limits. The normal operation envisages no change in ID fan speed but for adjustment and finetuning purposes, thereby providing a bias facility to adjust the optimum speed even at the entire range of operation. The similar interlocked operation is applicable as discussed in item (ii) and (iii) of the inlet vane above. There could be other possibilities as well where the main furnace pressure control will be controlled by varying speed and the vane may be kept wide open. The vane control may only come into operation when the demand signal for the speed control is beyond a certain range. The philosophy is almost the reverse to what has been discussed. Because in this case and most of the time the vanes are kept wide open, the pressure loss will be less.

7 DRUM LEVEL CONTROL, FEED WATER CONTROL General The boiler drum level control system is provided for the conventional drum boilers applicable for subcritical power plants with coal/lignite as the pulverized fuel. The boiler drum in this case acts as a reserve vessel with feed water and saturated steam as the inlet outlet. There are a number of control valves for drum level control with different types of operating ranges and for providing redundancy. To force the feed water into the drum, there are also a number of constant-speed feed water pumps or variable-speed feed water pumps. In case the feed water level in the drum becomes too high, water particles can be carried over by the main steam going to the turbine and may cause catastrophic damage. On the other hand, in case of a very low drum water level, the drum itself becomes overheated, which may also result in a catastrophic situation. In general, the drum level control or the feed water flow control has been provided with two modes of automatic operation: single- and three-element control. The set point is the same for the drum level controls meant for both modes

as set by the plant operator. For a single-element control system, the difference between the drum level measured/ process variable and the drum level set point is the error signal. This is fed to the controller to take care of the rate of water being pumped into the drum by adjusting the position of the feed water flow control valve. The very name of the three-element control comes from the three process variables: drum level, steam flow, and feed water flow.

7.1

Objective (Fig. 8.28)

It is one of the most important control loops of the subcritical boiler category with the objective of maintaining the drum level at a fixed value for the reasons stated above.

7.2

Discussion

In a large-capacity thermal power plant, the normal range of operation is accomplished by the three-element control strategy that usually covers a large boiler load variation from 30% to 100%. The drum level at low boiler load is accomplished by a single-element control system with a low capacity control valve as the FCE. There are generally two major control systems adopted for the three-element control strategy. One of them is to use the full capacity control valves (2  100%) as the FCEs with one 30% capacity valve or to use one 25%–100% valve with one 0%–100% bypass valve (say VRT or drag valves as discussed in Chapter 6). The other control strategy utilizes the services of the variable speed boiler feed pumps (BFP) through the hydraulic coupling between the BF pump and the motor with the help of the scoop tube actuator and/or the turbine-driven boiler feed pump (TDBFP). It has been observed through long experience that the three-element control system is a much more rugged and stable system than the single-element control. The advantage of using the three-element control strategy is that it can easily handle large and rapid load changes due to the fact that it is matching the mass balance between the main steam flow from the boiler and the feed water flow into it. The reason for using a single-element control is rather than a compulsion because the accuracy is always under question at a low range of flow measurements. As discussed earlier, the main two constituents are the feed water flow and the main steam flow measurements are based on empirical formula developed by using a flow measuring element like a flow nozzle (or an orifice plate for comparatively smaller plant) where the differential pressure produced across the flow element is proportional to the square of flow rate. It is well known that at low (water and steam) flow rates where the relations between differential pressures and flow rates are different from what is expected. In other words, the three-element control at low

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loads introduces unreliability in the control action and the single-element control is used at low loads as a natural choice. Normally, the operator starts the drum level control in manual mode and continues up to the full range of singleelement control, but due to the simple nature of the control strategy, the control system can well be placed in automatic no sooner feed flow is established after any of the BFPs is started. As generally observed, the flow measurements are considered reliable with standard accuracy at about a reading of 20% or more. By keeping some cushion, when the flow figures are around 25%–30% of the measuring range, the drum level control can be transferred to the much-desired three-element control.

7.2.1 Drum Level Computation The drum level is measured by differential pressure transmitters to be installed in line with Fig. 12.24A and C. It shows the temperature equalizing column has been used to ensure equal temperature vis-a-vis density in both limbs of the DPT. The level is measured by DPT to eliminate the incumbent pressure P1 of the steam space at one limb. P1 is subtracted from P1 + P (pressure due to water head) on the other limb. Therefore, DP ¼ pressure due to water head P ¼ h*r*g. For a particular place, g is always constant. So the water head P varies with h (level) and density, which in turn depends on temperature. In the drum, the incumbent pressure is due to the saturated steam pressure, and for saturated steam, each pressure corresponds to a particular temperature. Temperature is a sluggish parameter so saturation pressure is chosen to compensate/correct the density effect.

7.2.2 Shrinking and Swelling Phenomenon The shrinking and swelling in the boiler drum is a very common phenomenon and must be taken care of in determining the three-element drum level control strategy of a subcritical boiler plant. Shrinking and swelling are caused due to a change in pressure in the drum, which also changes the water density. Rapid excursion of load vis-a-vis steam extraction causes a tremendous change in the boiler drum pressure, followed by the drum level. The hot water closer to the saturation point contains steam bubbles in the drum. During a rapid increase in load, a severe rise in level takes place because of an increase in the number and volume of the bubbles, which are the consequences of a drop in steam pressure (i.e., swelling/expansion of bubbles) as a result of load increase and also by the increase in steam generation from the greater firing rate to match the load increase. The double effect of lower pressure and higher temperature makes the situation worse. If the level in the drum becomes too high at this time, the water carryover into the

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superheater or the turbine maybe the worst consequence if the boiler is not made to trip from a very high water level. Conversely, whenever there is a decrease in demand, the drum pressure increases and the firing rate changes, thus reducing or shrinking the volume of the bubbles (that is, the bubbles get smaller). An abrupt and significant loss in load could result in high drum pressure, causing shrinkage severe enough to trip the boiler on a low level. A more severe catastrophic situation followed by a boiler trip at high firing rates may create a condition similar to a furnace implosion. If the implosion is severe enough, the boiler walls are likely to be damaged due to the high vacuum in the furnace. However, these increases/decreases in level are a transient phenomenon that is well taken care of by the control strategy. It is true that the firing rate change affects the drum level, but not to the extent that may make it so severe as done by the abrupt change in steam extraction rate considered as the most significant cause of shrinking/swelling of the steam bubbles.

7.3

Control Loop Description

See Figs. 8.27 and 8.28.

7.3.1 Measurement of Different Parameters 7.3.1.1

Drum Level

Here, the level of the drum is measured with sufficient redundancy at both ends of the drum. This is necessary as there may be a difference in level in view of the long length of the drum and the dynamic nature of the process. The transmitters are not connected to the drum directly (due to the fact of reducing the number of nozzles on the drum itself) but to the temperature-compensated constant head unit (Fig. 12.21) connected to the drum stand pipe provided to facilitate multiple tapping points. After necessary voting, the selected raw level signal is compensated for pressure and the average value is taken for further action in the control loop.

7.3.1.2

Feed Water Flow

The feed water flow to the boiler drum is measured with sufficient redundancy and after the necessary voting, the selected raw level signal is compensated for temperature and the average value is taken for further action in the control loop. The attemperation water flow with due compensation for pressure and for temperature is added to get the total feed water flow, depending on the relative locations of the flow-measuring device and the spray line tapping.

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FIG. 8.27 Drum level control.

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FIG. 8.28 Drum level control (low load).

7.3.1.3 Main Steam Flow This flow measurement may be taken directly from the flow nozzle/transmitter combination or from the turbine firststage pressure after suitable characterization through the first-stage pressure/steam flow relation algorithm. The measurement is done with sufficient redundancy and after necessary voting, the selected raw level signal is compensated for temperature. The other steam flow signals such as HP bypass steam flow and auxiliary steam flow, if any, are also measured and suitably compensated for pressure and temperature. They are then added to get the total steam flow value for further action in the control loop.

7.3.2 Different Control 7.3.2.1 Control Loop Description With Single-Element Control As previously discussed, there are two stages of controlling the drum level, that is, single-element and three-element control. Although the three-element control is accomplished in two ways (as discussed later), there is no such option available for single-element control. The finally selected drum level signal acts as the process or measured variable

and forms the error signal with the fixed drum level set point. The controller is with the PID algorithm for any adjustment for optimum tuning. A low-load control valve acts as a FCE. In general, tuning of the single-element controller necessitates adjustments with large proportional and very little of integral gain settings. 7.3.2.2 Control Loop Description With ThreeElement Control 7.3.2.2.1 Three-Element Control With Flow Control Valve as Final Control Element Drum level control normally uses the cascade control strategy, consisting of the formation of a master and a slave controller. The drum level signal, being the prime element of this control loop, forms the error signal with the fixed set point and is connected to the controller designated as the master one. The main steam flow is an indication of the rate at which water is being extracted from the drum. This measured or characterized (from first-stage pressure) main steam flow is taken as a feed forward signal and added to the output of the master controller.

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An antiswelling and shrinkage circuit algorithm is customarily provided to take care of the problem, as discussed in Section 7.2.1 of this chapter. The main steam flow, before being added to the drum level (master) controller, is routed through this algorithm, which corrects the steam flow signal against a quick change. The amount of correction can be varied as required by adjusting the limiter function gradient and integral function integration rate. The correction would become zero with time when the steady-state condition is reached. For an abrupt increase in steam flow, a negative correction would apply to lessen the magnitude of the actually measured/calculated steam flow so that less water is requested for the time being to arrest the inflated drum water level (due to low drum steam pressure) from further increasing so as not to trip the boiler/MFT from a very high drum water level. The reverse is the action when there is a sudden load throw-off and the water supply is not lessened, as should have been the normal case, so that the boiler/MFT tripping can be avoided from a very low drum water level. Another method of incorporating the antishrinkage and swelling function as per another school of thought is to utilize the derivative signal of the drum pressure itself. For any quick change in load, the drum pressure ought to change as a result of energy imbalance. The rate of change with respect to time is the index of the load change rate and the signal thus derived is added to or subtracted from the steam flow (as per the tendency of pressure change, that is, increasing or decreasing) plus the drum level (master) controller output finally becomes the demand or set point for the feed water flow requirement. The difference between this set point and the measured feed water flow now becomes the error signal for another controller (slave) for feed water flow regulation. The controller output is then utilized to modulate the position of the redundant feed water flow control valves. So far as the tuning of the three-element control system is concerned, it has some special requirements. Here, the feed water flow (slave) controller must be tuned with the much faster integral action than that of the drum level (master) controller. This philosophy is in fact applicable to all types of cascade control strategies. There could be another simple way to achieve the same goal. Here, a demand is created by the steam flow feed flow error (in the ideal case, steam flow and feed flow should match, and only during changes will there will be an error/difference between them). Thus demand created by a controller is added to the demand from the drum level controller. For steam flow, feed flow and drum level measurements with necessary corrections as stated in the main description are equally applicable here. For the drum level control loop, the strategy is otherwise simple without many manual interlocks or control tracking. Though not specifically shown in the above drawings, the control loops may be forced to run in manual mode in case

all pumps are not running or the drum level signal/feed water flow valve control output goes out of range, as may be deemed necessary by the appropriate authority. Three-element control with scoop tube actuator for control of DP across feed valves (Fig. 8.29) When the three-element control for the drum level is accomplished by the flow control valves, then another control loop is also envisaged for controlling the differential pressure (DP) across the feed control valves to enable them to operate smoothly. Controllability is also improved for control valves when subjected to a DP with a predictable range. In some plants, this DP is maintained at a fixed value by adjusting the BFP speed through hydraulic coupling visa-vis the scoop tube actuator. BFP speed control may be referenced for a schematic representation of the idea for implementing the control loop in a typical 250 MWTPS with a drum boiler. In this control loop strategy, the DP across the feed valves is measured with sufficient redundancy, and after necessary voting, the selected raw DP signal is taken as a measured/process variable to form the error signal with the desired/set value of the DP, which is not a fixed value as in the other types of power plants, as stated earlier. This particular power plant has a variable set point for the DP after due characterization of the selected (high) position transmitters of the first-stage attemperation spray valves. All these position signals are passed through a high selection algorithm. There is another fixed input of the high selector that ensures the minimum value of this selector output as an 80%–90% (adjustable) position of the attemperation spray water valves. After characterization as per the predictable relation of the flow control valve DP with respect to the spray valve position, the output is again passed through a high/low selector that limits the derived set point from going beyond the maximum and minimum values of the DP across the flow control valves. The error signal thus obtained drives the PID controller whose output is utilized for positioning the scoop tube actuator for varying the speed of the BFPs. The control loop strategy is made with a view to maintain the DP across the feed valves to such an extent that the upstream pressure of the flow control valve, which is incidentally the upstream pressure of all the spray control valves as well, slides to the minimum (for better efficiency) required value sufficient enough to push an adequate amount of spray water with the spray valves almost fully open. It is quite obvious that a wider opening of a control valve demands less DP across it with the flow being same. With the downstream pressure of the spray valves being dictated by the process, that is, the boiler load, the upstream pressure is now the minimum pressure required for the necessary flow of spray water. This minimum pressure calls for the minimum discharge pressure of the BFP required at that point of operation, thus minimizing the pumping loss.

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FIG. 8.29 BFP speed control (2  100% MDBFP).

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The flow control valve readjusts its opening to suit this DP across it to maintain the feed water flow to maintain the drum level. This control strategy thus ensures a minimum but adequate upstream spray water pressure to keep the spray control valves operating in a satisfactory manner without running the BFPs at an unnecessarily high discharge pressure. For single-loop control strategy, the scoop tube actuators would remain in a fixed position, irrespective of whether the control mode is put on auto or manual. With one BFP running, the second standby BFP (for 2  100% configuration) should have its scoop tube on auto follow-up mode so that, in the event of a tripping of the running pump, the second pump should start the forward feed to the boiler without much loss of time. The maximum allowable delay time in starting the second pump is dictated by the boiler drum storage capacity and the permissible time limit required to come to a very low drum level from a normal drum level. For 3  50% BFP configuration, the standby BFP would have its scoop tube actuator on auto follow-up mode to track the maximum position of the two running BFP’s scoop tube actuators. For TDBFPS, one motor-operated BFP is required as a fallback. The hydraulic coupling scoop tube always tracks the TDBFPs so that in case any TDBFP trips, the motorized BFP (with discharge valve open) can immediately meet the flow requirement. The BFP motor shall be rated in such a way for a loaded start. The BFP running at safe pressure against the flow delivered at a particular point of time is detected for interlocked operation. Here, the characterized BFP discharge header pressure represents the limit of a safe discharge flow at the particular speed with which the pump is running. When the actual flow is more than the safe flow, binary signal is generated in the high/low signal detector (high in this case). This would force the scoop tube actuator to raise the speed of the BFP so that the operating point is shifted as to make the safe flow become more than the actual flow at a higher discharge pressure. An interlocked signal is also arranged at the same time to prevent the flow control valve from further opening, increasing the feed flow to the unsafe region of operation. For a 3  50% BFP, individual pump suction flow is to be measured and compared to the safe flow from the characteristic curve at the corresponding discharge pressure. 7.3.2.2.2 Three-Element Drum Level Control by Pump Speed Variation (With Scoop Tube Actuator/ Turbine Driven BFP) (Fig. 8.30) The designers/manufacturers/customers of modern power plants prefer the feed water flow to be controlled by the variable speed feed pump with a scoop tube for the hydraulically coupled motordriven BFP (MDBFP) and turbine-driven BFP (TDBFP). This arrangement requires a low load feed control valve for 0%–30% boiler load (single-element control), as

previously discussed in Section 7.3.2.1 of this chapter. For a load higher than 30%, the usual control strategy, that is the drum level controller with the addition of total steam flow, duly incorporating the antishrinkage and swelling algorithm, becomes the set point of the feed water flow controller. The simplified schematic typically represents the control loop of a 500 MW power plant having one MDBFP and two TDBFPs with 3  50% pump configuration. Here, parallel to the low-capacity FW control valve, that is, in the main FW line, there is another valve of the throttling cum isolation type that would be made (manually or automatically) to open slowly up to 100% at a boiler load of >30%. By this action, the low-capacity FW control valve would close gradually to 0% and then the FW is controlled by adjusting the speed of the pumps with the main line isolating valve fully open. The error between the feed water flow set point and the feed water flow measured/process variable is connected to the FW flow controller, but only after a manual or automatic changeover selection representing the boiler load has reached >30%. As depicted in the above control strategy (Fig. 8.30), there are a number of controllers shown as PID in general, but the tuning of those controllers is very important. As discussed earlier, the speed controller may have a very fast integral action rate whereas the FW water controller may have a slower integral action rate with a drum level controller having a further slower integral action rate. However, all the whole tuning activities would depend on the plant condition, the quality/capability of the control systems, and the availability of equipment/accessories. To avoid a three-stage controller situation, in some control strategies the drum level controller is eliminated and the FW controller error signal is generated directly from the drum level set value minus the measured value plus steam flow with the suitable antishrinkage and swelling algorithm. Then, the FW flow signal is subtracted to get the error signal for the FW controller. When the boiler load is around 30%, the main line valve is gradually opened and the low-load valve is gradually closed; it may be achieved automatically but manual selection often is a better option from a loop stability point of view. DP mode error: This signal is selected from the DP error across the lowload feed valve or the pump safe operation criteria through a maximum selection. The DP across the low-load feed valve is measured and the error with the DP set point forms one of the two inputs, which, if selected, controls the pump speed. This is, however, applicable to low-load operation only and the valve DP error signal is ignored at higher loads. The other input that is the pump safe operation signal. The maximum of the measured flow signals of each individual pump (with sufficient redundancy and voting arrangement) passing through the characterizer (flow versus discharge pressure) is considered a safe discharge pressure

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FIG. 8.30 Three-element drum level control by pump speed variation.

at any given flow and is input to a subtractor along with the actual BFP discharge pressure. This signal, if selected via the maximum selector, would be trying to maintain the safe discharge header pressure of the BFPs by adjusting the speed of the running pumps. This part of the control loop is known as DP mode. The DP mode error signal is compared with the flow mode error signal in another maximum selector and acts as an input to the flow controller related to the boiler load. Another flow controller is provided to take care of the pump protection by bringing the individual suction flow to a safe value, according to the common discharge pressure. An individual pump’s protection-related flow controller is free to act within the upper limit derived by adding a 2% (for example) signal value to the minimum selected signal of the two flow controllers stated above. Normally, the common boiler load-related controller would be selected as long as the discharge pressure is adequate enough to administer the required feed water flow.

The minimum selector output of flow controllers then constitutes the speed demand of the individual pump and is compared with the pump speed to determine the operating speed of the concerned pump. As already indicated, that the MDBFP speed is varied by adjusting the scoop tube position of the hydraulic coupling, TDBFP speed is made to vary by the electrohydraulic governor control.

8 SUPERHEATER TEMPERATURE CONTROL General Superheated steam is principally used in power generation plants as the driving force for turbines. The application of the Rankine cycle in thermal power plants is available in most textbooks relating to the thermodynamic properties of steam. Very brief discussions are also in various sections of

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Chapters 1 and 2, from which it is apparent that superheated steam is more thermally efficient than saturated steam when the question of driving a turbo generator arises. As the extra heat causes the transmission of more energy than saturated steam, it is utilized for additional power generation from the available quantity of steam. Although superheated steam contains a large amount of heat energy, this energy is available from three sources, that is, the enthalpy of hot water, the enthalpy from evaporation (latent heat) of water to steam, and the enthalpy from the degree of superheat. The bulk of the energy is in the enthalpy of evaporation, and then from hot water and less energy from the superheated steam, which represents a comparatively smaller proportion of the total heat content. Using superheated steam (meaning no condensation in the pipelines) has some added advantages that are very important, such as: (a) It eliminates the problem of entering wet steam (with water droplets) inside the turbine, which causes increased friction, enhanced silica deposits, and pitting/erosion of turbine metals. (b) It prevents water carryover in the saturated steam, which could cause steam formation and may give rise to overspeeding of the turbine, which is extremely dangerous. (c) It permits higher steam velocities through the pipeline (up to 100 m/s), which automatically suggests that smaller pipelines can be used (provided that the pressure drop is not excessive).

8.1

Objective

The objective of this control (considered one of the most important) loop is to maintain a constant temperature of the boiler outlet steam or turbine inlet (fixed or sliding pressure) with the provision of variation due to transmission loss. The saturated steam from the boiler drum is superheated by adding heat through various superheaters (LHS and RHS). Before them are desuperheaters having water spray chambers. Hot feed water is sprayed through these spray chambers as per the command of the temperature controller, so that the steam temperature at the final superheater inlet goes down adequately so as to gain the required temperature inside the final superheater to maintain a constant temperature at the final superheater/boiler outlet.

8.2

Discussion

Superheated steam temperature control is a critical consideration for the efficient running of the steam generator vis-avis the turbo generator unit. Steam temperature needs to be stable to accomplish the highest turbine efficiency. This

would also reduce the fatigue of the turbine metal, as discussed in Section 6 of Chapter 9. As the steam temperature is controlled by spraying water with a comparatively colder temperature into the steam spray chamber, constant temperature control is a bit problematic as the temperature measurement itself is a sluggish phenomenon and the time delay arises out of the process itself. The spray chambers are generally located much before the superheater whose outlet temperature is to be measured and controlled. The changing process dynamics—including system gains, time constants, and delays—are also responsible for concern that varies as the turbine load changes. Considering all the aspects, it is apparent that the superheat steam temperature control has always been a critical subject for the efficient and most favorable operation of a power plant. The control strategy, in normal practice, employs cascade controls with controllers having PID algorithms at different levels to regulate the superheat temperature. The state-of-the-art technology has made modern controllers with self-tuning algorithms, enabling the controller block to adjust the controller parameters such as the proportional band, the integral time constant, and the derivative action rate. However, some instrumentation manufacturing houses and researchers feel that the self-tuning controllers may not be capable of tackling the situation alone against the tendency of changing gains and time constants of the controlled system during the disturbed condition. New adaptive control strategies are now proposed for the improvement of superheat steam temperature control. The algorithm of these controllers is based on a cascade control system having PID functions, but self-tuning parameters are programmed to adjust themselves following the recursive least squares (RLS) method. As claimed by the inventors, the smart adaptive system can cope with the adverse disturbances much better than a conventional control function algorithm, with a faster and more accurate response as well as more effectiveness. Another type of control algorithm, popularly known as a predictive adaptive controller, is also advantageous for maintaining the superheated steam temperature of large thermal power plants. Adaptive techniques combined with a predictive element enable the controller to incorporate continuous adjustments of parameter tuning by tracking the plant dynamic variations. An advanced and new predictive adaptive controller algorithm uses a function series approximation technique called dynamic modeling technology (DMT), which is, as claimed, particularly designed to take care of the system under control with a long time delay and long time constants. The design is said to have incorporated the unique ability to build the models automatically while operating in a closed-loop configuration as well as controlling the transient responses that take place during boiler load changes. The model, or in other words the mathematical representation of the process response that normally takes expertise of a complex nature and detailed knowledge, need

Boiler Control System Chapter

not be required here to be built as the DMT modeling method does the same thing by the use of advanced mathematical functions. For details, relevant textbooks may be referenced. With superheated steam temperature control being a critical control loop, a different approach has also been made to address the problem with the help of a system that is known as state variable control. It is a unique set of variables that describes the state of a dynamical system at any point of time. In other words, the future behavior of a particular system can be predicted automatically to a close proximity if the data required by the state variable technique are provided judiciously. To be more precise, the state variables themselves represent the state of any type of system in general. In a thermodynamic system, the state variable input data are pressure, temperature, heat content, and related parameters of the system such as enthalpy, entropy, and internal energy. It is practically a special method of preparing a model of the concerned system employing a time-domain technique. Here, the actual physical system, that is, the thermodynamic representation of the boiler and turbine, is described by an ordinary differential equation of the nth order. With the help of a state variable, a set of first-order differential equations is calculated and grouped, exploiting the use of a compact matrix notation that is depicted as a model and widely known as the state variable model. At any instant, the state equations receive the current inputs along with past states and bring out the relation to the current state and output of the system so as to enable the control system to generate the appropriate output.

8.3 Control Loop Description (Figs. 8.31 and 8.32) All the methods other than the self-tuned and optimized cascade PID controllers are explored so that a reduction of steam temperature fluctuations around the set point is obtainable. However, the control loop strategy for superheater steam temperature control is discussed, incorporating the PID controllers for easy understanding of the control philosophy. Figs. 8.31 and 8.32 are schematic representation for implementing the control loop in a typical 250 MWTPS having a drum boiler, two-stage spray water attemperation systems, and reheat steam temperature control through a gas recycling camper and a spray water attemperation.

8.3.1 Measurement of Different Parameters The following measurements are done with triple redundancy and voting. The selected parameters are utilized in the control loop: (i) First- and second-stage attemperator outlet temperature (left and right side).

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(ii) Platen SH and final SH outlet temperature (left and right side). (iii) Primary SH inlet pressure.

8.3.2 Control Loop Description The steam path in the system for which the control strategy is described incorporates a primary SH, a first-stage attemperator, a Platen SH, a second-stage attemperator, and a final SH ad seriatim, irrespective of their physical location. 8.3.2.1 Control Loop Description for Two-Stage Attemperation 8.3.2.1.1 Control Loop Description for Second-Stage Attemperator Outlet Temperature Control Loop The ultimate measured/process variable is the final SH outlet temperature, which is compared with the constant set point (adjustable at low load) to form the error signal for connection to the master controller (or the outer controller) with PID algorithms. A derivative functional is normally provided in the temperature controller to compensate for the sensor’s inherent sluggish behavior. The controller output now becomes the variable set point of the second-stage attemperator outlet temperature controller and forms the error signal along with the measured/process variable; it is connected to the controller. This PID controller may be termed the slave/inner controller and generates the output for the position adjustment of the second-stage attemperator spray valves. As already indicated, the second-stage attemperator is located (in the steam flow path) just before the final SH. The second-stage attemperator provides the necessary spray water injection while the main steam is flowing through it to adjust the attemperator outlet temperature at a value just needed to maintain the final SH outlet temperature at a constant value after the necessary temperature gain within the final SH. The steam flow (in some plants, the air flow) is added to the controller output as the feed forward signal. The interlock shown from the steam flow <25% is provided to block the attemperation flow up to a 25% load. 8.3.2.1.2 Description for First-Stage Attemperator Outlet Temperature Control Loop Now comes the first-stage attemperator outlet temperature control. Actually, the first- and second-stage attemperator outlet temperature control loops are interconnected with each other in a cascade mode of control, justifying their interrelation within the system. The first-stage attemperator outlet temperature control loop is also configured in a master/slave mode whose master controller receives its variable set point from the final SH steam temperature master controller. The first-stage attemperator, with its comparatively larger spray capacity, sets the temperature at the secondstage attemperator inlet or, in other words, the platen SH outlet such that the second-stage attemperator maintains,

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FIG. 8.31 Superheater steam temperature control.

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FIG. 8.32 Final superheater steam temperature control.

in the long run, the exact mean spray water flow while effectively controlling the final main steam temperature at the required value. Both the control loops are almost identical with the difference that the final SH steam temperature master controller (the outer controller) has a fixed set point whereas the first-stage attemperator control loop master controller has a variable set point, which is just required to attain a value as dictated by the final SH steam temperature master controller. However, as the final SH steam temperature master controller output is actually the variable set point or the desired temperature at the second-stage attemperator outlet, it cannot also be the set point for the firststage attemperator control loop master controller (outer controller) meant for the second-stage attemperator inlet or, in other words, the platen SH outlet. Therefore, the differential temperature as envisioned by the designers is added to the desired second-stage attemperator outlet temperature (as derived from the final SH steam temperature master controller output) to get the anticipated variable set value of the second-stage attemperator inlet temperature.

The measured and selected values of the platen SH outlet temperatures of the left and right sides are then averaged and become the process/measured variables for the second part of this cascade control loop. The error signal is then connected to the first-stage attemperator control loop master controller (outer controller), the output of which becomes the variable set point for the controller assigned for the first-stage attemperator outlet temperature control but after a maximum selector. Under certain operating conditions, there is the possibility of the control system demanding a first-stage attemperator outlet temperature below the saturation temperature, which is taken care of through the incorporation of this additional function so as to ultimately protect the platen superheater. The primary SH inlet pressure (or drum pressure) is measured and the corresponding saturation temperature is calculated through a function generator. To this signal is added (as a positive bias) an increment of around 20–35°C (meaning a certain degree of superheat),

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depending upon the operating pressure (the higher the pressure, the lower the permitted increment). The resulting summated signal, that is, the saturation temperature plus a certain degree of superheat, is treated as the minimum permitted first-stage attemperator outlet temperature and becomes another input of the above-mentioned maximum selector to ensure that the steam temperature does not come down near saturation at the first-stage attemperator outlet temperature after the application of spray water. With this variable set point, the first-stage attemperator outlet temperature slave controller the output of the controller is added with a feed forward signal from the total steam flow as generated in the drum level control loop (Fig. 8.27) after appropriate characterization. The output of the summator is now the position demand of the spray valves of the first-stage attemperator for maintaining its outlet temperature. 8.3.2.1.3 Safety Interlocks of the SH Temperature Control Loop The following safety interlocks are incorporated to protect different components of the thermal circuit. They are described as follows: (i) The spray water isolation valves and block valves are interlocked to close automatically if the steam flow (or the equivalent boiler load) is equal to or <25% of the continuous maximum rating (CMR) to protect the superheater system from the effects of water droplets due to inefficient atomization of the spray water at low loads. Another interlocked operation is envisaged to release the signal to auto operation of the spray water modulating valves, unless the isolating valve is fully open; this logic prevents the possibility of the modulating valves being open due to a position demand request from the control loop when the availability of the spray water is uncertain. (ii) The spray water modulating valves are interlocked to the closed position through a bias close signal from the steam flow <25% CMR when the isolating valve is fully closed; it also causes the controller output to trip to manual. 8.3.2.2 Control Loop Description for Boiler With Single-Stage Attemperation (TT Burner Boilers) The description of the above control loop takes care of a typical power plant of 500 MW capacity having a steam drum, a firing system with a burner tilting arrangement, and provisions for both fixed and sliding pressure control systems. 1. Discussions: There are some differences in boiler design. For example, for TT burner boilers, the majority of the superheaters and reheaters are platen where the heat absorption is mainly by radiation, requiring more spray flow at lower loads. For this reason, during

start-up and low-load, the set point is very critically chosen, as discussed in clause no. 8.3.2.2.3 below. For the same reason when the load is high, most of the heat is taken away by steam so the spray flow (mainly for SH steam) goes to the very minimum (even zero). The other type described in clause no. 8.3.2.1.2 has major sections of superheaters and reheaters as convection types, meaning more heat will be absorbed by the steam as the load increases with a tendency for the steam temperature to rise, hence a higher spray flow at a higher load. Also, burner tilting (mainly used for reheater control) will have an impact on heat radiation in superheater platen zones also. Therefore, the effect from the same will be taken care of here. Now, a boiler load index is the output of the boiler (in a drum boiler, the derivative of the drum pressure also contributes energy output, the d/dt of the drum pressure is added with the load index) and must match the fuel demand; otherwise the unbalanced energy will try to disturb the steam temperature. Such effects are used in the control strategy to make the sluggish temperature loop responsive. 2. The measurements are desuperheater (DSH) and final SH outlet temperature (left and right side). 3. The control loop is basically a cascade type and has a similar control strategy as that of the second-stage attemperator outlet temperature control part described above. The ultimate measured/process variable is the final SH outlet temperature, which is compared with the temperature set point to form the errors (Fig. 8.33). Here, the set point is made variable, and is programmed as a function of the unit steam flow signal for both constant pressure control and sliding pressure control, but with separate characteristics. A manual set point is also provided and the output of a minimum selector passes the set point for generating the error signal, which is connected to the master controllers (outer loop controllers) with PID functional blocks (algorithms). A derivative function is usually provided for the temperature controllers to compensate for the sensors’ inherent sluggishness. When the difference between the left and right side temperatures at the final SH steam outlet header is within the limit, their average temperature acts as the measured/process variable for both the master controllers of the left and right side temperature control loops. In case of a high difference between the two sides, then the average signal is no longer considered as the measured/process variable. Instead, the individual the final SH steam outlet temperature becomes the measured/process variable for the respective control loops. The controller output now becomes the variable set point of the desuperheater or attemperator outlet temperature controller and forms the error signal with the measured/process variable for the controller. This PID controller, which may be called the slave controller (inner controller), generates

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FIG. 8.33 Superheater steam temperature control (500 MW TPS) with burner tilt.

the output to position the desuperheater or attemperator spray control valve providing the necessary spray water flow injection to the main steam flowing through the desuperheater. It also adjusts its outlet temperature at a value just needed to maintain the final SH outlet temperature as desired after the necessary temperature gain within the final SH. With reference to clause no. 8.3.2.2.1, the feed forward signals provided to make this control strategy more responsive are burner tilt position, main steam flow, drum pressure, and fuel demand. The RH temperature, when controlled through the burner tilt operation, causes the SH temperature excursion, which is taken care of by the burner tilt position feed forward signal. The same logic applies to the fuel demand rate change. For instance, when fuel demand increases, it may cause overfiring; the spray valves are then open in advance to counter the effect due to overfiring. The steam flow and drum pressure (derivative) signals are taken as the feed forward signals after the effects of

overfiring. At that time, the steam flow and/or drum pressure would rise and is used as the index to recognize the tendency for the temperature to drop. This is thus countered through these signals by closing the spray valves. All these signals are duly characterized to generate suitable output signals and are summated to make an input signal for a PD controller. The output is again added to the output of the slave controller (or the inner controller) to become the position demand for the individual spray valves.

9

REHEAT TEMPERATURE CONTROL

General Exhaust steam from the high pressure turbine (HPT) is brought back to the boiler for making it again superheated (or reheated) steam at a lower pressure, but normally to the same temperature as the main steam temperature. The thermodynamic properties of steam and the application of the Rankine cycle in the thermal power plant suggests that superheated steam is more thermally efficient than saturated

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steam when the question of driving the turbo generator arises. That is the reason as to why the exhaust steam from the HPT is again reheated and the extra heat causes the transmission of extra energy. This is utilized for additional power generation from the available quantity of steam.

(i) Control through gas recycling damper (Babcock boiler). (ii) Control through gas dampers (main line) or bypass dampers (Babcock boiler). (iii) Control through burner tilting mechanism (CE boiler).

9.2.1 Control Through Gas Recycling Damper

9.1

Objective

The objective of this control loop is to maintain a constant reheat steam temperature at the boiler outlet, meaning an almost constant temperature at the IP turbine inlet subject to variations due to transmission loss. The exhaust steam from the HPT is superheated by adding heat through various heat exchangers known as reheaters. Before the reheaters (left side and right side), there are arrangements for desuperheaters having water spray chambers in the CRH lines. Hot feed water is sprayed through these spray chambers as per the command of the temperature controller so that the steam temperature at the inlet of the reheaters goes down adequately so as to gain sufficient temperature, while passing through the reheaters, for maintaining constant temperature at the outlet of reheaters vis-a-vis boiler outlet. Desuperheaters are utilized as the last resort when all other FCEs reach their end positions.

9.2

Discussion

Similar to superheated steam temperature control, reheated steam temperature control is also a critical parameter for accomplishing the highest turbine/generator efficiency. This would also reduce the fatigue of the turbine metal, as discussed in Section 6 of Chapter 9. It may be noted that reheat steam, having a low operating pressure, is subjected to different thermodynamic conditions than superheater steam. For the reheat system, problems may arise out of injecting colder spray water associated with unwarranted effects on the overall efficiency. The control system for reheater steam temperature thus normally avoids water spraying because long and uses a primary control system which would take care of the control of reheat steam by either adjusting through position control of tilting burners or by apportioning of flue gas flow through the superheater and reheater banks or recirculation of flue gas into the furnace from suitable take-off point. The provision of spray water injection is kept when the main FCE has reached the extreme position or the temperature has shot up to a particular predefined value when emergency spray is necessary. The system so far prevents the need for spray water and confines the use for fine tuning and emergency purposes only. In some control schemes, the system is used for controlling the furnace outlet temperature as well. Therefore, there are different schools of thought for adapting the control philosophy (other than spray water control), depending on the type of boiler manufacturer. Basically, those are reheat temperature controls by:

For this control, a damper at the chimney inlet is provided in a common flue path at the discharge of the ID fans. This arrangement ensure the generation of a back pressure with sufficient magnitude so as to force the flue gas from the ID fan discharge header to the furnace again through a separate duct connected between the main flue line and the furnace hopper. This recycled gas flow controlled by the dampers alters the furnace absorption and mass flow of the flue gas, which maintains the steam temperature within range at the reheater outlet. In this case, the size of the ID fan will be higher because it handles more flue gas. There is another method of injecting flue gas into the furnace where the take-off point is much nearer to the furnace, which means the flue gas has a much higher temperature but much lower pressure. Recirculation fans are provided to generate pressure higher than the furnace. The gas recycling damper does the rest of the things. Some added advantages of having a flue gas recirculation system for reheat temperature controls are: (i) Total mass flow of the flue gas increases, enhancing more heat transfer to each heater bank. (ii) Due to the admission of colder flue gas, the temperatures at different stages of the furnace/boiler would go down, though the overall enthalpy would increase and so does the heat transfer. (iii) As the colder flue gas is injected near the burner, the resultant low temperature would help in the generation of less SOx and NOx compared to a system without a gas recirculation damper. With the take-off point for the gas recirculation system being at a low pressure zone, gas recirculation fans are necessary to ascertain that the flue gas passage back to the furnace through a long way. By controlling the gas recirculation flow, the steam temperature of both the superheater and reheater may also be controlled. With the gas recirculation damper, the reverse flow of very hot flue gas must be arrested to protect the recirculation fans when they are not running.

9.2.2 Control Through Main Path Gas Dampers or Bypass Gas Dampers In this arrangement, the quantity of flue gas passing through the reheater is varied by the gas bypass dampers to control the reheater temperature. The gas dampers do the apportioning of the flue gas flow through both the superheater and the reheater banks by adjusting their position. Some arrangements allow two

Boiler Control System Chapter

separate and dedicated sets of dampers in the flue gas path of both the superheater and reheater banks controlling the individual flue gas flow. With the dampers being located across the main path and controlling the total flue gas volume, the control system ensures that the dampers do not get a closed signal simultaneously, which may lead to constriction of the flue gas path. The resultant overpressurization may damage the boiler structure. To obviate the untoward situation, the control philosophy suggests that when one particular set of dampers is fully opened, only then is the other set allowed to throttle. Control through gas dampers is a slow response system and for large units, a sudden rise in temperature following a rise in furnace heat input may call for emergency spray to cope with the load demand.

9.2.3 Control Through Burner Tilt Mechanism The steam temperature control system is genetically different in two types of furnaces, that is, one with a tangentially fired tilting burner and the other having fixed burners. By this arrangement, the burning zone is raised or lowered by the burner tilting mechanism. The burners are corner-fired and focused tangentially to a common imaginary circle. When firing starts, there forms a huge fireball with swirling action. As all the burners in a corner are gagged to a common actuator and all the four corners get the same positioning signal, the fireball moves vertically upward or downward as the burner assemblies move up or down. Such repositioning of burners vis-a-vis the fireball changes the pattern of heat transfer to the superheater and reheater banks and thus controls the steam temperature. The burners are so arranged that tilted up or lowered down and so the flame envelope in the furnace causes a good variation in the amount of radiation heat received by the reheater and superheater. In fact, the firing system in any type of furnace of a power plant boiler having reheater banks affects the steam temperature of both the superheater and the reheater. It is very difficult to control both steam temperatures by a single control system, as corrective action for one steam heater bank may have an adverse effect on the other bank, which calls for separate control strategies.

9.3

Control Loop Description

9.3.1 Control Loop Description With Gas Recycling Damper and Spray Water Attemperation 9.3.1.1

Measurement of Different Parameters

The measurements necessary with sufficient redundancy and voting include gas recycling flow and reheat attemperator flow, reheater outlet steam temperature (LHS/ RHS), DP across the gas recycling damper, position of the gas recycling damper, position of the reheat steam outlet

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valves (for temperature balancing), main steam flow, and furnace pressure. 9.3.1.2 Control Loop Description The FCEs in the system are the gas recycling damper, the stack inlet damper, the reheat attemperator valves, and the reheat steam outlet valves (for temperature balancing). 9.3.1.2.1 Function of Gas Recycling Damper (Fig. 8.34) The steam temperature is measured at both the outlet legs of the reheaters and averaged after selection and voting to form the ultimate measured/process variable for this control loop. The control strategy utilizes the recycled flue gas flow to the furnace hopper by throttling the single gas recycling damper receiving the controlled input command from a temperature/flow cascade control action. The PID (temperature) controller employed for this purpose has a set point adjuster for setting the desired value of the reheat steam temperature control system. The controller output is then summated with another PID (flow) controller, the output of which signifies whether the requirement of gas recycling flow is satisfied. The gas recycling flow signal as measured forms the measured/process variable for this part of the control loop and the set point is derived from the main steam flow (as the load index), duly characterized to give the corresponding expected recycled flue gas flow. The (temperature) controller output trims the flow controller output to derive the required desired position of the gas recycling damper. This signal forms the set value of the position controller while the actual position of the damper is measured and connected to the position controller output, which is utilized to modulate the gas recycling damper. 9.3.1.2.2 Function of Stack Inlet Damper (Fig. 8.35) A secondary part of the reheater steam temperature control assists the main control loop to function properly. Its sole function is to maintain the differential pressure across the gas recycling damper at a constant value. The stack inlet damper acts as the FCE in this control loop. The DP across the gas recycling damper is measured and after selection/voting, passes through a maximum/minimum limit to form the measured/process variable for a separate controller whose set point adjustment is made through a manual setter and id set at a fixed value. The controller output is utilized as the positioning command for the stack inlet damper, which modulates to maintain the DP across the gas recycling damper. It thereby ensures sufficient pressure head to force the flue gas from the ID fan discharge duct to the furnace chamber through the hoppers. Interlocked operation prevents a damper closing command when the furnace pressure is high.

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FIG. 8.34 Reheater steam temperature control by gas recycling damper.

FIG. 8.35 Stack I/L Damper control (reheater steam temperature control by gas recycling damper.

9.3.1.2.3 Function of Reheat Steam Outlet Valves (for Temperature Balancing) (Fig. 8.36) There are two butterfly valves located in the reheat steam line in each leg. The purpose of this control loop is to maintain equal steam temperature at both the LHS and RHS pipe lines. This is done by slightly restricting the steam flow through the low temperature leg and vis-a-vis increasing the steam flow through the high temperature leg. The steam temperatures of both reheater outlet legs (LHS and RHS) are measured and averaged to form the common set value of two PID controllers, of whose measured/process variables are the individual reheater outlet steam temperatures. The outputs of these controllers are the position demands of the butterfly steam valves acting inversely so as to minimize the error. The purpose of the control strategy is not a fixed desired value, but to lessen the temperature difference between the two legs. Another purpose of this loop is to ensure a minimum steam side pressure loss. For doing that, the control loop envisaged a separate PID controller whose fixed set value is the 100% position and the measured/process variable is the maximum selected position transmitter signal of the above two butterfly valves. The controller output is added to the main controller output to form the combined position demands of each valve. By this arrangement, the maximum

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FIG. 8.36 Reheater outlet steam temperature control (by balancing control).

position selected valve would try to reach 100% and the other valve position would also increase by the amount, but the difference would remain the same. This is done by a minimum integration rate action and a high proportional band to allow a slow output signal until one valve reaches the 100% position without much disturbing the temperature balancing action. As already discussed, there are spray water control systems for maintaining the reheat steam temperature in emergency cases after the gas recycling damper alone fails to bring down the temperature. The normal control loop function is achieved by the gas recycling damper, but due to any reason, the temperature may shoot up. If that condition persist, then the spray control valve would come into action to save the reheater from burnout. The dedicated controller for this purpose has the same temperature set value but added (biased) with some more degree (around 5–7°C) to prevent this loop from interfering with the normal loop. The spray control valves remain closed unless the temperature crosses that biased amount.

The controller gets its measured/process variable from the average reheat steam temperature. The output becomes the RH attemperator water flow demand or set value for another controller, with the RH attemperator water flow signal measured directly as the measured/process variable. This controller output now becomes the position demand for the spray control valves. An interlocked operation ensures that the gas recycling damper is automatically closed when the RH attemperator spray valve opens; at that time, the ID discharge damper is mechanically arranged with a limited stroke by using a mechanical stop or setting the linkage so that the full stroke of the actuator provides partial movement of the damper.

9.3.2 Control Loop Description With Gas Dampers 9.3.2.1 Control Loop Description With Gas Damper in Main Flue Gas Path (Fig. 8.37) There are two types of arrangements for the boilers having reheater temperature control by gas dampers.

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(A)

FIG. 8.37 Reheater temperature control with gas bypass dampers.

(B)

Boiler Control System Chapter

For some boilers, gas dampers are provided in the common flue gas path as the FCEs for reheater steam temperature, which, when positioned, acts as a three-way proportioning valve that takes the task of apportioning the flue gas flow through both the superheater and reheater banks. This means that the total flue gas flow would be uninterrupted with the ratio of gas flow through the SH, and the RH only would be readjusted. In some boilers, two separate and dedicated sets of dampers are provided in the flue gas path of both the superheater and reheater banks controlling the individual flue gas flow. As these dampers are located across the main path, they control the total flue gas volume that may interrupt gas flow during auto control operation. In that situation, the flue gas path will be constricted so badly that the overpressurization may damage the structure itself, which is taken care of by not issuing a closing signal to both dampers simultaneously. To be on the safe side, one particular set of dampers throttles only when the other set of dampers is fully opened. Interlocked operation would also ensure that no gas dampers get a fully closed signal at any time during the entire range of operation. Intermittent operation of emergency spray valves may be necessary here as the control through gas dampers involves a slow response system for large units. Whenever there is a possibility of sudden overheating accompanied by a rise in temperature following a rise in furnace heat input vis-a-vis a large load demand in a small span of time, the spray valves are expected to take care of the situation. The set point of the spray loop is also derived from the loop shown in Fig. 8.37B. As shown in Fig. 8.37A, the measured variable (RH O/L temperature) is compared with the adjustable set point and the error thus created is sent to the PID controller. In order to make the loop more responsive, the load index is added at the output as the feed forward signal. As the water spray is an emergency or secondary control system in case of reheat temperature control, the spray valves are normally shut unless the temperature at the reheat outlet reaches a predetermined value higher than the normal set value. 9.3.2.2 Control Loop Description With Bypass Gas Dampers The control strategy is the same as the main line gas dampers, but here, bypass dampers in the SH and RH gas path are used to position in the opposite direction, as shown in Fig. 8.37B. During start-up and at low load, the superheater bypass would be wide open and the reheater bypass would be at a minimum position. As the load increases, the reverse will be the operation. The aim of the loop is to maintain the DP across the damper at a nearly constant level by adjusting

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the loop parameters and relationships at all points of operations. The set point of the spray loop is also derived from the loop shown in Fig. 8.37B.

9.3.3 Control Loop Description Burner Tilting Arrangement 9.3.3.1 Measurement of Different Parameters Measurements with sufficient redundancy and voting include burner tilt position, RH O/L steam temperature (LHS and RHS), RH desuperheater O/L steam temperature (LHS and RHS), and MS flow. 9.3.3.2 Control Loop Description The FCEs are the burner tilting arrangement and the RH attemperation valves. In the earlier stages, the burner tilting arrangement was utilized to control the reheat temperature only. Nowadays, the same is being utilized to control any of the superheat or reheat outlet temperatures, depending on the demand of the situation. In larger units of boilers with TT burners, the area of platen superheaters is increased so the burner tilt controls can be used for temperature control of either the SH or RH, based on demand. As discussed in the previous section, in these cases the two loops (SH and RH temperature control) are interactive, so provisions are now made for selection through maximum demand—because the major heat transfer is not by convection. The description of the control loop takes care of a typical power plant of 500 MW capacity having a steam drum, a firing system with a burner tilting arrangement, and provisions for a sliding pressure control system. Though this control loop needs a separate entity, it is included in the section of RH temperature control as many power plants of low/medium capacity still incorporate a burner tilting arrangement only for RH temperature control with the feed forward signal to the SH temperature control system. 9.3.3.2.1 Function of Burner Tilting Arrangement (Fig. 8.38) Here, the average control error signals from both the SH and RH controls loops are connected to the individual controller; one output, as selected through the maximum selector signifying the control signal related to the lower temperature out of the two, turns out to be the position demand of the burner tilting arrangement. Interlocking signals are provided as per the following logic: (i) When the steam flow vis-a-vis the boiler load is less than or equal to 25% MCR or at the MFT, the burner tilt would maintain its base position, that is, the horizontal position only.

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(ii) In case any spray water valve opens fully, the burner tilt raise command would be inhibited for protecting both the SH and RH elements from overheating.

9.3.3.2.2 Function of Reheat Spray Control Valves (Fig. 8.38) The measurements are RH desuperheater (DSH) O/L temperature (LHS and RHS), the final RH O/L temperature (LHS and RHS), the burner tilt position, and the MS flow. The control loop is basically a cascade type and has a similar control strategy as that of the superheat temperature control part (Section 8). The ultimate measured/process variable is the RH outlet temperature (LHS/RHS), which is compared with the temperature set point to form the error. Here, the set point is made a variable one that is programmed as a function of the unit steam flow signal for both constant pressure control and sliding pressure control, but with separate characteristics. This error signal is connected to the master controllers (or the outer loop controllers) with PID functional blocks (algorithms). A derivative functional block is provided to compensate for the sensors’ inherent sluggish behavior.

When the difference between the LHS/RHS temperatures at the final SH steam outlet header are within the limit, their average temperature acts as the measured/process variable for both the master controllers (or the outer loop controllers) of the LHS/RHS temperature control loops. In case of a high difference between the two sides, then an average signal is no more considered as the measured/process variable and instead the individual RH steam outlet temperature becomes the measured/process variable for their respective control loops. The controller output now becomes the variable set point of the desuperheater or attemperator outlet temperature controller and forms the error signal along with the measured/ process variable and is connected to the controller. The PID controller, also termed the slave/inner controller, generates the output for the position adjustment of the desuperheater or attemperator spray valves. Desuperheaters or attemperators are located (in the steam flow path) just before the reheater. The attemperator provides the necessary injection of spray water flow while the cold reheat steam is flowing through it to adjust the attemperator outlet temperature at a value just needed to maintain the reheater outlet temperature at the set value after the necessary temperature gain within the reheater.

FIG. 8.38 Reheater (superheater) temperature control by burner tilt and spray water.

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9.3.4 The Spray Water Valves in Reheater Control Loops: Common Features

10 MISCELLANEOUS BOILER CONTROLS INCLUDING OVERFIRE AIR DAMPER

There are certain common features regarding spray water valves that are applicable irrespective of the primary arrangement of reheat temperature controls. Those are indicated below:

10.1

(i) The spray water valves are generally provided at the inlet of the reheater to avoid any overheating, which may damage the reheater elements. Another reason for keeping the attemperation at the inlet is to also help avoid chances of water carryover. (ii) All the primary control systems are designed to prevent any need for spray water in normal operation, confining such use for fine tuning, secondary control systems, and emergency purposes only. However, in large boilers (TT burner), as discussed here, the spray may be used as the primary control that also requires a minimum water flow at high load for the reasons already discussed in the previous section. (iii) In some control schemes, the system is used for controlling the furnace outlet temperature as well. (iv) All the FCEs utilized by the primary system are sluggish and any large step load increase may necessitate the action of spray water valves. (v) In addition to boiler-specific interlocked operation, the spray valves must immediately be closed in case of turbine tripping. The reason behind the interlock is that the turbine tripping causes a collapse in the reheater flow. In that case, as per the recommendation of the Turbine Water Damage Prevention (TWDP) Act, cold spray water cannot enter the turbine anyway.

9.4 Other Reheat Steam Temperature Controls This type of control is used for the compartmented boilers with mill bias. These are three-element controls such as reheat temperature, load demand, and total air flow with mill bias. Three-element controls are applicable mainly in the applications with rapid load changes as well as in variable steam and attemperation pressure. Here, the load demand is trimmed with reheat temperature control within the maximum allowable load demand. This load demand is compared with total air flow with mill bias. The controller decides the demand for excess air and mill bias. At lower loads, mill bias is increased first and then excess air bias, whereas at higher loads, it is just the reverse; the function generators are selected accordingly. The excess air is introduced in the bottom idle compartments. Details are available from ISA.

General

Many other control loops for the boiler unit, not yet described in specific sections separately, are indicated below, but there may be some other control loops not mentioned that are required for a particular type of make: (i) Atomizing steam/air pressure control. (ii) Air heater cold end or steam coil air preheater (SCAPH) temperature control. (iii) Hot gas temperature control. (iv) Continuous blowdown (CBD) tank level control. (v) SCAPH drain tank level control. (vi) Overfire air damper control.

10.2

Objective

(i) Atomizing steam/air pressure is controlled at a fixed value facilitating HFO/light fuel oil (LFO) atomization for proper burning of the oils. (ii) The purpose of the air heater cold end or the SCAPH temperature control loop is for maintaining the average value of the cold end temperatures of the air heater, that is, at the air inlet and flue gas outlet at a fixed value above the dew point, which may vary from season to season and can be set in the controller accordingly. (iii) Hot gas temperature is controlled to minimize the flue gas temperature imbalances between the primary and secondary air heater outlets. The temperatures of the two air heaters are compared and by positioning the gas dampers, the distribution of flue gas is readjusted in an effort to eliminate the difference between them. (iv) Continuous blowdown (CBD) tank level control is provided to maintain a fixed level in the tank to facilitate the transfer of drum water blown down as unacceptable quality for the steam-water cycle. (v) SCAPH drain tank level control is provided to maintain a fixed level in the drain tank, where the heating steam is condensed at the outlet of the SCAPH and collected, to facilitate the transfer of water for further use. (vi) Overfire air damper control. The objective of this control loop is to minimize the NOx level as per the directive of the local pollution control board. The FCEs are the OFA dampers for the tangentially fired burners. By proper positioning of these dampers at various elevations and locations, the desired level of NOx can be maintained.

10.3

Discussion

(i) Atomizing steam/air pressure control is required for HFO or LFO atomization. The pressure of the

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atomizing media is always maintained at a fixed value, but the same may be more or less than the operating oil pressure, depending on the type of burner used. (ii) Air heater cold end or (SCAPH) temperature control is provided for maintaining the average cold end temperature above the dew point so as to prevent condensation at the air heater surfaces and thereby prevent the resultant corrosion of materials. The flue gas contains sulfur oxides (SOx) and moisture, which condenses when the temperature goes down at the flue gas outlet part of the air heaters (cold end of AH). This may happen from both ends, that is, when the incoming air temperature itself is low due to noncongenial ambient conditions where the air is sucked and/or the flue gas temperature is not capable enough of the raising air temperature. As a result, it may become as low as near the dew point. To avoid that situation, this control loop is provided for a separate steam coil air preheater getting steam from a separate auxiliary steam source. Normally, the SCAPH is located in the bypass duct at the outlets of each FD fan for preheating the air. For a separate primary air heater system, SCAPH should also be provided in each PA fan bypass duct. By this arrangement, the flow control valve provided at the SCAPH inlet of the steam line modulates as per the command from the controller and maintains the requisite temperature around 10°C, more than the acid dew point for flue gases. It is to be noted that the service SCAPH is not normally required but for start-up, low load and may be under abnormal or due to climatic conditions. (iii) Hot gas temperature control, as already described, is to minimize the gas temperature imbalances between the primary and secondary air heater outlets. The sustained differences in those would result in stratification of flue gases at the ID fan inlet, jeopardizing the unit efficiency. The two temperatures are compared and input into a controller whose output is the input of a function generator of each damper control loop. In auto operation, the controller for any temperature imbalance would tend to close the hotter side damper while the colder side damper would remain in the open position. Limit values are provided to restrict the damper movements between the preset maximum and minimum values. These dampers are to be made 100% manually open during start-up, and those positions are sent to the ID fan as start permissive. (iv) Continuous blowdown (CBD) tank level control and SCAPH drain tank level control The above two controls are provided to maintain the level only to facilitate the passage of the incoming media as and when required.

(v) Overfire air damper control In certain furnaces, overfire air (OFA) dampers are provided to control the NOx (NO2 + NO) level in the product of combustion, that is, the flue gas. The NOx level is also restrained through provision of the flue gas recirculation damper. As discussed earlier, the production of NOx in a thermal power plant depends on many factors, namely time, temperature, turbulence, stochiometric ratio, etc., which is described as thermal NOx as airborne nitrogen (N2) and oxygen (O2) reacts with each other during the combustion process and can be kept under control with the help of OFA dampers. The other source of NOx may be from the organically bound nitrogen compound in the fuel itself. NOx formation and control loop strategies have been discussed in detail in Section 10.6 of this chapter.

10.4

Auxiliary Steam (BAS)

10.4.1 General Auxiliary steam in a power plant plays a great role, especially during start-up of the boiler and turbine. For smaller units without a bypass system, the boiler and turbine may have to be started simultaneously, so in those cases, separate auxiliary steam headers for the boiler and turbine known as boiler auxiliary steam (BAS) and turbine auxiliary steam (TAS) may be desirable. Larger units generally consist of a common auxiliary steam header to supply auxiliary steam to the boiler and turbine. During start-up of the boiler, it is started with oil requiring BAS for FO heating/atomization, SCAPH (maybe)—thus, the requirement for auxiliary steam is high. Similarly, during turbine start-up, the requirement for auxiliary steam is as high as for deaerator pegging, the starting ejector, etc. In larger units, the turbine is generally started after the boiler is a little stabilized through the bypass system, suggesting that boiler start up means no requirement for auxiliary steam for the turbine. Similarly, the turbine start up means no auxiliary steam requirement for the boiler, as it is already stabilized. Thus the load from the common header is well distributed in the time sequence, hence it is better for larger units with a higher requirement for auxiliary steam having a common header in place of an individual BAS and TAS. Whenever there are units in one plant (in the same geographical location), the auxiliary steam headers of each unit and the auxiliary boiler (if any) may be interconnected so that during the initial start up of one unit, the auxiliary steam may be supplied from another unit. Another aspect of the common auxiliary steam header is important. In larger units, the CRH pressure is high enough (>30 kg/cm2) to form an auxiliary steam header instead of forming the same from the MS to minimize energy loss due to large pressure and

Boiler Control System Chapter

temperature reductions. However, until the time the CRH line pressure is high enough, the source of auxiliary steam is MS, as shown in Fig. 3.15. Normally, auxiliary steam headers are formed with P ¼ 10 kg/cm2 and T ¼ 210°C for medium plants and with P ¼ 16 kg/cm2 and T ¼ 230°C for large plants. As discussed earlier, the requirement of for auxiliary steam (whether BAS or TAS) varies greatly during start-up and normal operations. At the time of startup, the MS pressure (the source of BAS or TAS) may be lower than when the unit is stabilized. During this time, larger auxiliary steam flow is necessary, so at a lower pressure drop, a higher flowthrough control valve is required. On the contrary, when the system is stabilized, the control valve experiences a high pressure drop to allow a lower flow, which dictates the necessity to use separate control valves with higher and lower capacity, as shown in Figs. 3.12 and 8.40. In this book, both BAS and TAS have been dealt with separately in Chapters 8 and 11, respectively. However in this section of Chapter 8, the common auxiliary steam header aspect has also been discussed, and is not repeated in Chapter 11. 10.4.1.1

Objective of Boiler Auxiliary Steam Control

The purpose of this control is to obtain a header of constant pressure and temperature, irrespective of changes in the boiler load. 10.4.1.2 Objective of Common Auxiliary Steam Header The purpose of this control is to obtain a header of constant pressure and temperature, irrespective of changes in the load in the boiler and turbine as it is supplying auxiliary steam to both the boiler and turbine. 10.4.1.3

Discussions

The control system is basically for a pressure reducing and desuperheating station (PRDS) with two separate controls for maintaining the header pressure and temperature at constant value. In the available two types, one may be with the combined PRDS with the same control valve responsible for pressure reduction that has the desuperheater built in it, where water is controlled and sprayed using temperature control. In the other design, a pressure-reducing control valve is followed by a separate desuperheater where the water spray is controlled to maintain temperature. One typical combined PRDS is shown in Fig. 8.41. 10.4.1.4 Control Loop Description In these loops, airlock relay and solenoid valves have been introduced to indicate that in case of failure of the air supply and electrical signal, the control valves may be locked in their previous position, that is, to attain the fail lock position.

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10.4.1.5 Boiler Auxiliary Steam Control (Fig. 8.39) This system consists of two separate loops: 1. Boiler auxiliary steam: Pressure control: Here the auxiliary steam header pressure is measured in one of two mode and compared with a fixed set point. The deviation thus created is used to drive a P + I controller. The output of the controller through the A/M station and I/P converter regulates the pressure-reducing valve to maintain constant pressure at the auxiliary steam header at all loads. 2. Boiler auxiliary steam: Temperature control: Steam temperature at the auxiliary steam header, that is, at the outlet of the pressure-reducing valve/desuperheater, is measured and compared with a fixed set point and the deviation thus created is fed to a P + I + D controller (as temperature is a slow-changing parameter). The output of the controller regulates the condensate flow to the desuperheater to control the temperature at the auxiliary steam header. In the figure under reference, a separate desuperheater has been shown, but it can be combined with a pressure-reducing station also, as shown in Fig. 8.41.

10.4.2 Boiler Auxiliary Steam Control (Fig. 8.40) BAS high capacity and low capacity. As discussed in clause no. 10.4, there may be a necessity for high-capacity and low-capacity PRVs. The basic pressure and temperature control loop description is the same as discussed in clause no. 10.4.1.5. However, the loops may be operative in a split range, when the load is high then both the low and high capacity valves shall be operative. When the load reduces, the high-capacity valve shall start closing first. After that, the pressure shall be maintained by regulating the low-capacity valve. These high- and low-capacity control valves can be taken into service with the help of the interlock of the upstream isolating motorized valve from the loop. Until the low-capacity valve is 80% (
) open, the upstream isolating valve of the high-capacity control valve may be kept closed. Similarly, when the high-capacity control valve is around 20% open, the associated isolating valve may be closed and the low-capacity isolating valve may be opened. These two high- and low-capacity pressure-reducing valves are kept in parallel. The desuperheater is placed in series after these pressure-reducing valves. The temperature control, single and common to both the high- and low-capacity PRV, is the same as discussed in clause no. 10.4.1.5. However, if necessary, the temperature control for each high- and low-capacity PRV can be provided. In case of combined PRDS design, there shall be two such temperature control loops.

FIG. 8.39 Boiler auxiliary steam pressure and temp. control.

FIG. 8.40 High and low capacity BAS.

Boiler Control System Chapter

10.4.3 Common Auxiliary Steam Control (Fig. 8.41) This is a header common for both the BAS and the TAS. Here, there may be three loops. One common pressurecontrol loop and one temperature-control loop for MS and CRH. There will be two pressure-reducing valves; one each for MS/CRH to the auxiliary steam line. 1. Common auxiliary steam pressure control: Here, the auxiliary steam header pressure is measured in one of two mode and compared with a fixed set point. The deviation thus created is used to drive a P + I controller. The output of the controller, through two sets of A/M stations and I/P converters, can regulate the pressure-reducing valves in the MS and CRH lines to maintain constant pressure at the common auxiliary steam header at all loads. Any one will be active based on selection through the interlock discussed later (clause no. 10.4.5). The CRH pressure, when developed, will source the auxiliary steam header, but initially the MS supplies the auxiliary steam. Whenever the CRH is selected, the PRV in the MS line will be closed following a ramp circuit. 2. Common auxiliary steam temperature control: There are two sets of steam temperature control loops to regulate the condensate flow to the desuperheater after PRV in each for the line from the MS and the CRH (These desuperheaters may be combined with PRVs also as shown in Fig. 8.41 for combined PRDS.) steam temperature at

FIG. 8.41 Auxiliary steam header from MS and CRH.

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auxiliary steam header that is, at the outlet of the pressure-reducing valve and the desuperheater is measured and compared with a fixed set point; the deviation thus created is fed to a P + I + D controller as the temperature is a slow-changing parameter, hence Daction may be more effective. The output of the controller regulates the condensate flow to the desuperheater controlling the temperature at the auxiliary steam header. With suitable interlock, the condensate flow to the nonactive desuperheater has been prevented (discussed in clause no. 10.6).

10.4.4 Control Loop Operation (Figs. 8.39–8.41) In this part, the auto and manual operation of the loop has been discussed. 1. This loop, as per clause no. 1.2.1 of Section 1 of Chapter 8, trips to manual on transmitter failure and/ or selection. The operator needs to select the correct transmitter to continue with the loop. 2. Loop is operable in auto/manual position at any time. 3. There will be some additional signals for releasing control loops associated with (control valves CTV and CAV in Fig. 8.41) CRH PRV and the associated temperature control loop, as shown in Fig. 8.41. These loops can be released to auto only when the pressure in the CRH line is established. The control valve CTV in Fig. 8.41 has also been implicated as to prevent condensate flow when the associated pressure is not in service.

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10.4.5 Control Loop Interlock There may be some specific interlocks for the loops: 1. BAS (Figs. 8.39 and 8.40): In case the temperature at the desuperheater (after PRV) outlet, that is, at the auxiliary steam header, is > set value, then the PRV (both high and low capacity) shall be forced closed. Also, in case of signal failure, the associated solenoid valve shall be closed to attain fail lock condition of the associated valve (fail lock condition). 2. Common Header Interlock: a. Associated PRV shall be closed when the temperature > set value sensed by LVM. b. Whenever the PRV in the CRH line (CAV) is in auto and open >5% (say), the PRV in the MS line and the associated temperature control valve shall be closed, as shown in Fig. 8.41. Due consideration must be given while sizing the valves; there may be two sets of valves to cater to the requirements during start-up and normal operation. Typical parameters for PRDS valves in auxiliary steam systems are as follows: Some extreme conditions (typical parameters) for the PRV and temperature control valves are as follows in Table 8.2. High pressure drop, high temperature, and high noise are very important in selecting the valves for these applications, especially for PRVs. Cage-guided low dB trim with multiple holes is used to minimize the noise effect, etc. Use of auxiliary steam in boiler: Major uses of auxiliary steam include fuel oil heating, fuel oil atomization, and heating air in SCAPH.

10.5 Soot Blowing Steam PR and SCAPH Pressure Control General In a modern thermal power plant, there are steam requirements at different pressures and temperatures, depending on the nature and working parameters at the consumer ends. Soot blowing steam and steam coil air preheater (SCAPH) pressure control are examples of two such requirements.

10.5.1 Soot Blowing (SB) Steam Pressure Control SB steam pressure control plays a vital role regarding the cleaning of the furnace and the air heater heat transfer surfaces. In an SG plant, steam is readily available as and when the plant is operating. Suitable tapping point normally from auxiliary steam header whose process parameter (10–16 kg/ cm2 pressure, 210–250°C temperature) almost matches with the requirement of SB steam; exact requirement may be achieved through provision of separate pressure-reducing valves. 10.5.1.1

The objective of this control loop is to exactly maintain the steam pressure of the main SB header supplying all the furnace water wall and convection zone soot blowers. It is quite obvious that the MS and flue gas outlet temperatures are affected by the cleanliness of the heat-transferring surfaces. Soot blowing with the proper quality of steam as well as the proper sequence and frequency is the only measure to improve the overall efficiency and pollution control by reducing the unwanted accumulation of dirty substances. 10.5.1.2 Discussion The experience entails that SB steam quality must be around 10–15 kg/cm2 pressure and 50–60°C superheat with an aim to get sufficiently dry superheat steam to avoid moisture in the cleaning media. As the normal SB steam is sourced from the high-pressure steam already available, any reduction in the required pressure would raise the degree of superheat more than before. The source may be from MS, HR, or even from the auxiliary steam header. Normally, the source is so chosen that the temperature control is not necessary. 10.5.1.3 Control Loop Description (Fig. 8.42) The SB steam control loop in a typical 250 MW plant with a drum boiler and fossil (coal)-fired furnace is shown. The control loop is a direct, single, and simple type. 10.5.1.4

TABLE 8.2 Typical Parameters for PRV and Temp Cont. Valve Parameter

Pr. Red. Valve (PRV)

Temp. Cont. Valve

Inlet pressure

175/145 bar

190/165 bar

Outlet pressure

16/10 bar

16/10 bar

Temperature

540°C

160°C

Objective

Measurement of Parameters

Includes only SB steam pressure transmitters with sufficient redundancy and at the appropriate location to get an average and representative measurement. 10.5.1.5 Control Loop The measured/process variable is compared with a fixed set value to form the error signal for the controller whose output is the position demand for a pressure-reducing valve having capacity dictated by the maximum number of blowers undergo simultaneous operation.

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(A)

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(B)

FIG. 8.42 Soot blowing and SCAPH steam pressure control.

There may be some individual or an array of soot blowers requiring different inlet pressures for their operation, which is taken care of with self pressure-reducing valves for the individual or group of blowers while supplying from the main SB steam supply header.

10.5.2 Steam Coil Air Preheater (SCAPH) Steam Pressure Control SCAPH is one of the means for control of SOx through process control loops. The control strategy adopted is to check the temperature fall below a certain value at specific points for avoiding deposits of condensation of sulfuric acid (H2SO4) and sulfurous acid (H2SO3) vapors on the exposed metal. The minimum average of the gas and air temperature is maintained, by which the corrosion is expected to be checked by not allowing the acid condensation as discussed above. SCAPH is located just before the air heater so that the air temperature increases while entering the air heater. To implement this control, an external steam supply is required with separate control valves. The temperature/flow control valves provided need a steady and controlled steam pressure

at the inlet so that the requisite and ultimate temperature control is achieved. 10.5.2.1 Objective The objective of this control loop is to exactly maintain the SCAPH inlet steam pressure before the SCAPH temperature control valve. 10.5.2.2

Discussion

There may be more than one SCAPH for systems with separate heaters for secondary air and primary air. The requirement of steam supply pressure is normally the same and hence separate pressure-control valves may not be required. As the purpose is only raising the air temperature, the steam pressure may be around 5–7 kg/cm2. The source is normally from the auxiliary steam header. 10.5.2.3

Control Loop Description

Fig. 8.42B may be referred to for a schematic representation of the idea for implementing the control loop in a typical

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250 MW plant with a drum boiler and a fossil (coal)-fired furnace. The control loop is a direct, single, and simple type. 10.5.2.4

Measurement of Parameters

The SCAPH steam pressure is measured by a pressure transmitter with sufficient redundancy and at the appropriate location to get an average and representative measurement. There may be two different pressure-reducing stations if two types of air heaters (PA and SA) are provided with unequal steam pressure requirements. 10.5.2.4.1 Control Loop The measured/process variable is compared with a fixed set value, normally 10°C more than the acid dewpoint of the flue gas, to form the error signal. The controller output is the position demand signal of a pressure-reducing valve with the required capacity.

10.6

a lower temperature and form sulfuric acid (H2SO4) and sulfurous acid (H2SO3). When the flue gas temperature falls below the H2SO4 dewpoint, droplets of condensed H2SO4 are formed on the metal surface of airheaters and ducts exposed to the flue gas. Under these conditions, corrosion occurs because of the presence of a thin film of acidic electrolytes over the surface, giving rise to localized and uniform corrosion, also known as acid dewpoint corrosion. It has been observed that long or extended shutdown of the unit may cause deposits of corrosion-aiding agents. Too much excess air assists SOx formation; on the contrary, if the stoichiometric ratio is less, then unburnt constituents cause corrosion at water wall surfaces. Later cases are somewhat eliminated when an ever-oxidizing atmosphere is maintained near the water walls mainly used for delayed mixing, as discussed later. Unlike NOx, it cannot be minimized at the source but the condensation of sulfuric acid on the duct/air heater can be prevented by several methods.

SOx and NOx Control

General Different oxides of sulfur and nitrogen are termed SOx and NOx, and are generated as byproducts of combustion of different kinds of oils and coals in the furnace of the steam-generation plant. The fuels and atmospheric air contain these basic elements in various forms. After combustion, they are converted to their corresponding oxides with the presence of very high temperature, forming flue gas along with different oxides of carbon and other gases.

10.6.1 Objective The main objective of all these controls is to reduce the sulfur and nitrogen oxides traced as byproducts of combustion. There are several methods of reducing the SOx and NOx levels in a thermal power plant. Some methods suggest a suitable control process by reducing the generation of those air pollutant gases at their very respective sources. Some methods, on the other hand, incorporate a chemical process for reducing those generated gases before discharge to the atmosphere. Such processes, however, do not take care about the reduction of those gas generation at source instead incorporate plants to convert them into harmless compounds following the local pollution control board’s guideline.

10.6.2 Discussion 10.6.2.1 SOx As already discussed very briefly in Section 2.2 of Chapter 2, other aspects such as formation, aftereffects, and controls of SOx, are incorporated in this section. Sulfur dioxide (SO2) and trioxide (SO3) are produced during the combustion process as byproducts and are present in the flue gas. They combine with moisture contained in the flue gas at

10.6.2.2

NOx

NOx is not a compound/radical, but it represents a family of seven compounds/radicals and reacts in the atmosphere, forming ozone and acid rain. Out of these NOx, NO2 and is considered an important pollutant. Environmental concerns from NOx include but are not limited to: ground-level ozone and acid rain formation, aquatic acidification, and deforestation. The Environmental Protection Agency (EPA) established national air quality standards that define the quality requirements of air with necessary safety margins. Electric utility plants contribute around 22% of NOx formation due to human activities (the other major source being transportation,
56%). Like sulfur, nitrogen (N2) is also available from atmospheric air in quantity as well as from different kinds of fuel oils and coals being organic compounds that naturally contain N2. During the combustion process, only 5% of NO2 is present against 95% of NO in the total available NOx. The NOx produced from the source of atmospheric air is often called thermal NOx. Various test results and equations indicate that thermal NOx conversion is dependent on the temperature and concentrations of both N2 and O2 and the time for which the combustion takes place. It is also observed that the same depends on both a fuel-rich flame front (diffusion flame where fuel and air are introduced separately and mixed through turbulence during combustion) and a fuel-lean flame front condition (premixed flame where premixed fuel and air are introduced to the furnace). The other source of NOx generation is called fuel NOx, as the source is from fuels only. The test results show that this generation is dependent not on the temperature but on the availability of oxygen (O2). O2 reacts with the gaseous state of the fuel-bound nitrogen compounds such as NCH

Boiler Control System Chapter

and NH3 to generate NO in an air-rich combustion atmosphere only. On the contrary, these nitrogen compounds, being unstable, would simply reduce to N2, a harmless gas, only under fuel-rich conditions. To summarize, the following design strategies are important, (i) Lower thermal NOx level can be achieved by using a low excess air operating strategy and a furnace designed for a lower gas temperature by introducing various methods such as burners with low turbulence diffusion flames, overfire air compartments, efficient water walls, and a flue gas recirculation system. (ii) Lower fuel NOx level design suggests the provision of controlling air flow for mixing with the fuel in the initial burning zone or combustion chamber. (iii) Lowest NOx level can be achieved if the coals used have the lowest fuel-nitrogen and lowest fuel-oxygen/ nitrogen ratio. NOx generation thus can be reduced significantly and the methods, listed in Table 8.3 for ready reference, are typically adopted by the manufacturers to meet the stipulation of local/national pollution control boards and customer specifications. Major approaches to reduce NOx discharge into the atmosphere include either or both reducing the production of NOx or mitigating the NOx already produced. Out of these, the first may be less costly than the postproduction approach. Use of OFA in TT boilers is by far the most cost-effective way to control NOx. Some of the major NOx control methods have been tabulated (based on EPA technical bulletin November 1999) as Table 8.4, TABLE 8.3 NOx Reduction Percentage by Different Methods Methods/ Systems

Type of NOx Reduced

Reduction Possibility (
)

Flue gas recirculation

Thermal NOx

75%

Babcock design

Overfire air damper

Thermal NOx

75%

CE/ Babcock design

Low NOx burners

Thermal and fuel NOx

25%

Applicable to any boiler

Staged burners

Thermal and fuel NOx

70%

Applicable to any boiler

Air mixing and air flow control

Thermal and fuel NOx

70%

Depends on boiler design

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NOx control methods with advantages and disadvantages. Apart from those listed in the table, there could be some other methods such as reduced air preheat, inject oxidant, nonthermal plasma, etc. Some of the abbreviations used in the table are BOOS (Burner Out Of Service), FGR (Flue Gas Recirculation), SCR (Selective Catalytic Reactor), SNCR (Selective Noncatalytic Reactor), and LEA (Less Excess Air). To combat NOx pollution, three technologies are used: l

l

l

The primary technology is mostly concerned with air staging, that is, to reduce the availability of oxygen (less than the stoichiometric ratio) in the primary combustion zone and later balance the air downstream. The secondary technology is mainly concerned with fuel staging such as reburning, injection, and chemical reaction, such as SNCR (postproduction treatment). Posttreatment such as SCR. Apart from these, the use of oxygen in place of air utilizing an air separation plant is not uncommon. In IGCC, these have been discussed in the appendix. In ultrasupercritical boilers, in many system designs N2 is separated from air and oxygen is used so that there will be only a remote chance of NOx formation.

Following equipment/methods are utilized to curb the formation of NOx: 1. Low NOx burner (LNB) Fig. 8.47A–C: In an LNB, NOx formation is limited by regulating the temperature profile and stoichiometric ratio. The design features control the aerodynamic distribution and mixing pattern in the burner, always trying to delay complete mixing to the extent possible so that: l

l

Remarks

8

l

Reduced oxygen in the primary flame region to limit formation of both thermal and fuel NOx. Reduced flame temperature, hence less thermal NOx formation. Reduced residence time due to distribution to cause less thermal NOx formation.

Coal rank and volatile matter content have a direct impact on NOx formation in LNB. Lower rank coals have a more volatile release, which inhibits NOx formation near the burner on account of more conversion of nitrogen released in a fuel-rich environment near the burner into molecular nitrogen (N2). On the contrary, LNB can lead to economic losses on account of more unburnt carbon (UBC). UBC can have an impact on tubes, electrostatic precipitator (EP) performance, and marketability of fly ash (ASTM C618 limits UBC to 6% in fly ash). However, this can be circumvented by using more fine coal and changing the air/fuel distribution. Coal with greater fineness will be better for less NOx formation in LNB because less air will be required to carry it as well as less of a chance of UBC. On account

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TABLE 8.4 Major NOx Control Methods Basic Principle Reducing peak temperature

Chemical reduction of NOx

Technology

Description

Advantage

Disadvantage

Impact

Applicability

Low NOx burner

Internal staged combustion

Low OP. cost compatible with FGR

High capital cost

Long flame, fan capacity, turn down stability

All fuel

BOOS/OFA

Staged combustion

No cap. cost for BOOS, low cost for OFA

Higher air flow for CO High capital cost

Long flame, fan capacity, header pressure

All fuel, for BOOS multiple burners

FGR

<30% flue gas recirculated with air, decreasing temperature

High NOx reduction potential for low nitrogen fuels

Moderately high capital cost and operating cost affects heat transfer and system pressures

Fan capacity, furnace pressure, burner pressure drop, turndown stability

All fuels Low nitrogen fuels

Air staging

Admit air in separated stages

Reduce peak combustion temperature

Extend combustion to a longer residence time at lower temperature

Adds ducts and dampers to control air furnace modification

All fuels

Fuel Staging

Admit fuel in separated stages

Reduce peak combustion temperature

Extend combustion to a longer residence time at lower temperature

Adds ducts and dampers to control air Furnace modification

All fuels

Fuel reburning

Inject fuel to react with NOx

Moderate cost Moderate NOx reduction

Extends residence time

Furnace temperature profile

All fuels (pulverized solid)

SNCR (addon technology) a. Urea b. Ammonia

Inject reagent to react with NOx

a. Low capital cost. Moderate NOx removal Nontoxic chemical b. Low operating cost. Moderate NOx removal

a. Temperature dependent NOx reduction less at lower loads b. Moderately high capital cost. Ammonia storage, handling, injection system

a. Furnace geometry Temperature profile b. Furnace geometry Temperature profile

All fuels

SCR (add-on technology)

Catalyst located in the air flow, promotes reaction between ammonia and NOx

High NOx removal

Very high capital cost High operating cost Catalyst siting Increased pressure drop Possible water wash required

Space requirements Ammonia slip Hazardous waste disposal

All fuels

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TABLE 8.4 Major NOx Control Methods—cont’d Basic Principle

Technology

Description

Advantage

Disadvantage

Impact

Applicability

Removal of N2

Oxygen instead of air

Use oxygen to oxidize fuel

Moderate to high cost Intense combustion

Eliminates prompt NOx Furnace alteration

Equipment to handle oxygen

All fuels

Reducing peak temperature

Combustion optimization

Change efficiency of primary combustion

Minimal cost

Extends residence time

Furnace temperature profile

Gas Liquid fuels

Water/steam injection

Reduces flame temperature

Moderate capital cost NOx reduction similar to FGR

Efficiency penalty Fan power higher

Flame stability Efficiency penalty

All fuels as low nitrogen fuels

of the longer flame of LNB, a deeper furnace may be called for to flame damaging water wall. In addition to this, there will be water wall wastage (corrosion due to unburnt sulfur/ chlorides, etc. For such corrosion prediction, computational fluid dynamics (CFD) codes are available), especially for boilers with LNB and/or other means of external staging. The problem is acute in cases of supercritical boilers (more specifically using relatively high sulfur coal). For this reason part Offset auxiliary air is used discussed later. Low NOx Concentric Firing System (LNCFS) improves coal air mixing. It forms an air circle outside the fire all created by fuel PA, as shown in Fig. 2.10. This is mainly developed to retrofit a TT furnace. It produces a stable flame front with an inner fuel-rich core fireball, which helps in converting bonded nitrogen to form an N2 molecule. The air distribution philosophy behind a low NOx burner is depicted in Fig. 8.47B. As shown in Fig. 8.47D, in a TT furnace, normally there will be a concentric firing system (CFS) between two adjacent low NOx coal nozzles. Through the CFS, offset auxiliary air is introduced. The angle of these offset air nozzles that is, the yaw (horizontal) and tilt/pick (vertical), can be adjusted as shown in Fig. 8.47C. Normally, the tilt is automatically controlled as per RH (or SH) temperature control, that is, gagged with a burner tilt mechanism and the yaw is adjusted manually. Offset air is directed toward the furnace to reduce fouling and produce an oxidizing environment to minimize water wall wastage. LNCFS burners have nozzle attachments to allow coal to burn near the nozzle to minimize NOx formation. Normally, above the top coal nozzle, there will be a CCOFA, as discussed below.

2. Overfire air (OFA): As indicated earlier, about 5%–20% of the total air required is diverted from the primary combustion zone and injected through some air port in the downstream of combustion for complete combustion and to reduce UBC. OFA in wall-fired boilers with LNB can help NOx reduction by 10%–25%. In case of a TT furnace, OFA is an integral part of the design. In a TT furnace with OFA, an NOx reduction between 20% and >60% is possible, depending on the initial NOx level, but it is coupled with an increase in UBC and CO. However, the extent of this increase depends on the OFA design and coal property. There are two kinds of overfire air: l Closed coupled overfire air (CCOFA): In close proximity to the primary combustion zone, this is mainly responsible for reducing the residence time in a fuelrich primary combustion zone and increasing the residence time in a fuel-lean burning zone. l Separate overfire air (SOFA): Located distinctly distant from the primary burning zone as well as the burnt out zone, it provides additional residence time in the primary combustion zone and less residence time in the burnt out zone. l The combination of these two helps in reducing NOx and at the same time helps to reduce UCB. Dispositions of these dampers for TT furnaces have been shown in Figs. 8.47C and D. Just above the top coal nozzle, there is a CCOFA (like CFS) and above that there is another set of CCOFAs. In between the two CCOFAs, there is a port of CCOFA for tertiary air.

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Separated by some distance, there will be SOFA dampers. Some of the design features in a TT furnace are: l SOFA ports are above the wind box. l Increased separation between auxiliary air and the fuel admission nozzle. l Reduction of the control damper for secondary air flow. l Reduction of secondary air flow while maintaining system pressure drop and injecting velocity for efficient mixing. l Addition of separate tilt control of under bottom end air admission for CO control. l In a TT furnace, especially in larger or supercritical boilers, there will be two sets of SOFAs. Lower SOFAs are essentially in the corners and the tilt control is gagged with the burner tilt control. There will be upper SOFA normally above the lower SOFA, and these are mounted on side walls, as shown in Fig. 8.47C. Normally, the upper SOFA dampers are connected with the automatic control loops. The upper SOFA may be regulated to control NOx. Desired NOx set point is compared with the actual value, then based on the error thus created, the controller issues the position demand for the associated damper. There have been loops where there may be MAX selection between the set point and the output of the function generator (having the boiler load as input), so that there will be a dynamic set point to take care of changes in load for the boiler. However, the yaw of each of these is normally adjusted manually. Reburning (Fig. 8.47E): Up to 25% of the total fuel heat input is provided by injecting secondary fuel (
90% of air required by the stoichiometry of the secondary fuel) above the main combustion zone to produce a slightly fuel-rich reburnt zone. This results in a hydrocarbon fragment that comes in contact with the incoming NOx (from the upstream combustion zone), which, in a fuel-rich condition, forms hydrogen cyanide (HCN) and isocyanic acid (HNCO), and is finally converted to N2 molecules. The furnace dimensions are very important here so as to achieve the desired goal, where sufficient residence time is essential. An increase in reburn heat input and a matching decrease in the main combustion heat input will decrease the stoichiometry in the reburn zone with an increase in NOx reduction efficiency. 3. SNCR (Fig. 8.47F): This is basically post NOx production control, where reagents such as urea and ammonia are injected into the furnace above the combustion zone so that the NOx formed could be converted to N2 molecules as per the reactions indicated below:

ðNH2 Þ2 CO + NO + ½O ! 2H2 O + CO2 + 2N2 2NH3 + 2NO + ½O2 ! 2N2 + 3H2 O This injection can be done at the furnace where the temperature is above 1150°C. Urea is injected as an aqueous solution whereas NH3 can be an anhydrous or an aqueous solution. 4. SCR: discussed separately below. 5. Miscellaneous other systems: Water/steam injection methods: By injecting water or steam into the flame, flame temperatures are reduced, thereby lowering thermal NOx formation and the overall NOx levels. Water or steam injection can reduce NOx up to 80% (when firing natural gas) and can result in lower reductions when firing oils. FGR, as discussed at length in the reheater temperature control loop, could be another method to limit thermal NOx. For coal-fired units, this is good for RH steam temperature controls, but may not be a foolproof and effective method for NOx reduction. Control loop optimization also helps in reducing NOx. 6. Control loop considerations: As discussed earlier, the fuel-air ratio control by staging of combustions is a major way to combat NOx production control. Reburning control is also a part of combustion control. In case of tangential tilt burners, the tilt controls of the CFS and CCOFA are done as a part of the reheat/ superheat steam temperature control. As also said earlier, the yaw is usually manually adjusted. However, there may be separate auto control loops for SOFA, based on NOx measurements, so that in case of excess NOx production, more air may be admitted through this port to reduce NOx production by complete combustion. 7. Eight-corner method: There is another method to curb NOx generation. The B and W eight-corner firing is an example of the same.

10.6.3 Description of Control Loops The generation of SOx cannot be avoided during the combustion of fuels, but can be minimized by proper selection of fuels where the user has that liberty to select as per his discretion. However, once generated, its detrimental effect on the duct/equipment is minimized by providing separate subplants, namely a steam coil air preheater (SCAPH) with its associated control loops. Concerned control loops are also provided for flue gas desulfurization (FGD) plants meant for eliminating postproduction SOx by converting it to sulfites or sulfates. 10.6.3.1 Controls of SOx 10.6.3.1.1 Controls of SOx Through Main Plant Process Control Loops After various experiments, the relationship between the minimum metal temperature and the gas and air temperature has been established by which

Boiler Control System Chapter

the corrosion of the air heater-exposed metal can be controlled. Normally, the average cold end metal temperature of the main air heaters throughout the year is kept at a minimum of 10°C above the acid dewpoint for flue gases. The following methods are applied for the above controls: (i) Steam coil air preheater (SCAPH) is located just before the air heater so that the air temperature increases while entering the air heater. Here, the average of the gas outlet and air inlet temperatures is taken as the measured variable and controlled against a calculated preset temperature value, which will not allow the acid condensation as discussed above and in clause no. 10.3(ii). (ii) There is some arrangement made near the air heaters so that a portion of the total air is bypassed and the heat exchange takes place toward the amount of air that passes through the main line only. As the quantity through the air heater becomes less, the loss of temperature experienced by the flue gas is also less, which prevents the metal temperature from further going down. The gas dampers at the inlet of the airheater and bypass line would modulate as per the controller output with the input, just like the SCAPH control loop. The controller output is so adjusted that the bypass damper would modulate only when the main line damper is fully open. During operation, if the bypass damper goes to the maximum position, then only the main line damper would start modulating. An interlock should be provided so that both dampers cannot operate simultaneously. (iii) There is some other arrangement made near the air heaters so that a portion of the total hot air is diverted from the air heater outlet to the force draught fan (FD fan) inlet so that the air temperature increases while entering the air heater. The recirculated hot air flow quantity depends on the controller output with the same control strategy and inputs as described above. The amount of heat exchange that takes place would be almost the same (except the heat loss in the recirculation line and the additional heat required to raise the air temperature handled by the FD fan) as before toward more air passing through the air heater, but with a higher inlet temperature. The damper in the recirculation line modulates as per the controller output to maintain the average temperature of the flue gas outlet and the air heater inlet temperature. 10.6.3.1.2 Controls of SOx Through a Separate Chemical Process Plant There are totally separate and special types of chemical process plants that are employed for reducing the SOx level, and these are called FGD plants. As SOx or in particular SO2 are acid gases, the removal process requires an alkaline scrubbing reagent (scrubber) or

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sorbent to react and convert them into a sulfur compound other than the gaseous form. There are broad classifications through which they can be identified such as wet or dry and regenerable or nonregenerable; those are enumerated below: (a) Wet (nonregenerable) FGD processes include lime/ limestone forced/natural oxidation, lime/limestone inhibited oxidation, lime and magnesium-lime, seawater process. (b) Dry (nonregenerable) FGD processes include lime spray (dry and semidry), duct sorbent injection, furnace sorbent injection, gas phase oxidation/ammonia injection (both SOx and NOx). (c) Regenerable FGD processes include sodium sulfite (wet), magnesium oxide (wet), sodium carbonate (wet), amine (wet), fluidized bed copper oxide process (both SOx and NOx—dry), activated carbon (dry). Here, regenerable means the process where the main scrubber is regenerated at the end of the reactions and reused. A small percentage is required to be injected into the system to compensate for the cyclical loss. Scrubbing of sorbent-like limestone/lime is the most common method followed in FGD plants. It is a catalytic chemical process for the removal of SO2 produced during combustion. In this system, a sulfur compound combines with a calcium-containing sorbent, generally lime (CaO) or limestone (CaCO3), to form a slurry. The slurry after use can be treated as waste or a useful byproduct. Though there are several processes indicated above, three types of FGD plants are normally available for large thermal power plants using chemical reagents such as a wet scrubber (after ESP), a spray dry scrubber (before ESP) [dry and semidry], and a sorbent injector (furnace and duct). Wet Scrubber This type of SO2 removal system is the most efficient (>95%) with a gaseous and liquid phase reaction; SO2 is transferred to the liquid under saturated condition. In general, it results in a liquid waste stream requiring wastewater treatment and a slurry as a byproduct, which needs a disposal system. As broadly classified, three main processes characterized by the use of absorbents dictate the scrubber design itself along with the generation of the waste and byproduct. Theoretically, other types are also in use, but these may not have been manufactured recently. Those types include sodium-based or dual alkali-based systems. These two systems were developed to avoid the consequential fouling problem encountered from the lime (stone)-based wet scrubbing process. The other reason is the idea that the application of a higher reactivity of the sodium compound may affect higher SOx removal. These systems ultimately became unpopular due to higher costs, nonavailability, production of higher waste slurry, etc.

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In a lime/limestone-based wet scrubber, flue gas is sprayed with an aqueous slurry of lime [CaO (dry lime) and Ca(OH)2 (milk/slurry of lime)] or limestone (CaCO3). Sulfur dioxide (SO2) is removed during the series of chemical reactions between the SO2 and the slurry to form calcium sulfate (gypsum) and sulfite. The reactions are : CaO + SO2 + H2 O ¼ CaSO3 + H2 O ½with dry lime CaðOHÞ2 + SO2 ¼ CaSO3 + H2 O ½with lime slurry and CaCO3 + SO2 ¼ CaSO3 + CO2 ½with limestone slurry In some plants, the cost of FGD installation is offset to some extent by converting the slurry into a useful byproduct such as gypsum [the remaining sulfite to CaSO4]. This can be achieved with or without air added to the thickener or oxidation tank, which is referred to as natural or forced oxidation, respectively. The latter gives a better gypsum quality that finds wider application while the larger crystals produced render a simpler dewatering process. To do this, compressed air is blown either in the scrubber process or in the following stage as a part of what is known as forced oxidation. The reaction is : CaSO3 + O2 + H2 O¼)CaSO4 , 2H2 O

FIG. 8.43 Schematic diagram of SCR and FGD plants.

The clean gas is then sent through the gas to gas heater (GGH). The GGH is provided to raise the temperature of the flue gas at the chimney inlet as it goes down during the process that takes place at the absorption tower. The incoming flue gas after the ESP is utilized to heat the outgoing flue gas after the absorption tower, as shown in Fig. 8.43. The thermal performance of GGH is very significant, as the reheated gas outlet temperature must be kept above the minimum specified value to achieve adequate flue gas buoyancy and ensure plume dispersion. This is also required to get a sufficient chimney effect, which depends largely on the gas outlet temperature and the stack height. Finally, the reheated flue is discharged through the high stack. Efficiency of this type of plant is 99%. Generally, the system includes dewatering of gypsum for commercial purposes. The wastewater after proper neutralization is sent to an ash slurry sump or suitable place as applicable to suit the plant conditions. The plants discussed here do have other auxiliary systems, a good amount of/control and is accomplished generally by dedicated PLC with communication link to main plant DCS for relevant data exchange. In Japan, it is common practice to utilize a CaCO3 concentration analyzer to optimally control SO2, as shown in Fig. 8.45. However, the ESP must be located before the FGD for a gypsum recovery system.

Boiler Control System Chapter

The other types including sodium-based or dual alkalibased systems are also in use, but may not have been manufactured much in recent days; they are very briefly discussed, mainly for academic interest. (a) A sodium-based wet scrubber system uses sodium hydroxides (NaOH) or sodium carbonate (Na2CO3) as the absorbent and has a low liquid-to-gas ratio because of their high reactivity with respect to lime/ limestone slurry absorbent. The reactions are: 2NaOH + SO2 ¼ Na2 SO3 + H2 O and Na2 CO3 + SO2 ¼ Na2 SO3 + CO2 Further oxidation converts sodium sulfite (Na2SO3) into sodium sulfate (Na2SO4); both are highly soluble, meaning they need special disposal. If sodium sulfite (Na2SO3) slurry is used in place of Na2CO3, the reaction would be: Na2 SO3 + SO2 + H2 O¼)2NaHSO3 ðsodium hydrogen sulfite solutionÞ By heating this solution, the reaction reverses and Na2SO3 could be recovered rather than consumed. This process is called the Wellman-Lord process and was regarded as the most widely used wet and regenerative sorbent FGD treatment. The process is almost similar to the dual alkali process discussed later. Sodium sulfite (Na2SO3) acts here as the actual sorbent while the sodium hydrogen sulfite (NaHSO3 acts as the sulfur-binding compound. However, the sulfur is not passed on to the calcium, but when heated, it is released again as SO2, which is extracted as a concentrated mixture (approximately 85% SO2) with water for further processing to sulfuric acid. In the process of scrubbing, sodium sulfite or sulfate is also formed as a byproduct. Due to some process loss in the sodium content in the form of Na2SO4, a small percentage of continuous make up through Na2CO3 (soda) or Na2CO3, NaHCO3 (trona) is required to be added in the regeneration tank to balance this loss. The reactions are as follows:

and 2Na2 SO3 + O2 ¼)2Na2 SO4 (ii) Inside the regenerator: 2NaHSO3 ¼)Na2 SO3 + SO2 + H2 O (iii) In the make-up process: Na2 CO3 + SO2 ¼)Na2 SO3 + CO2 , Na2 CO3 , NaHCO3 NaHSO3 + NaHCO3 ¼)Na2 SO3 + H2 O + CO2 Sulfuric acid formation reaction:

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2SO2 + O2 + 2H2 O¼)2H2 SO4 In some systems, magnesium hydroxide [Mg(OH2)] is used as an absorbent and the reaction is: MgðOH2 Þ + SO2 ¼ MgSO3 + H2 O (b) Dual alkali-based wet scrubber system This system utilizes sodium-based reagents such as sodium hydroxide (NaOH) or sodium carbonate/soda (Na2CO3) as the primary absorbent for SOx treatment, similar to the Wellman-Lord process. Initially, when Na2CO3 (soda) or NaOH reacts with SO2 in the absorption tower, the following reaction takes place: Na2 CO3 + SO2 ¼)Na2 SO3 + CO2 and 2NaOH + SO2 ¼)Na2 SO3 + H2 O After the formation of Na2SO3, it further reacts with SO2 to form sodium hydrogen sulfite (NaHSO3) and comes out of the absorption tower as a sulfur binding compound. Calciumbased reagents are then applied to this slurry for regeneration of the basic reagents, that is, (NaOH) or (Na2CO3). This method was thought of due to the problem that arose for using a lime scrubbing system such as low solubility of lime and limestone in water and gypsum scaling problems. The solubility of sodium salts is much higher, which led to this concept based on a scrubbing liquor with NaHCO3 and Na2SO3 as the SOx-binding compounds. The principle of the process is given in Fig. 8.44A. The reactions at different places are given below: (i) Inside the absorption tower: Na2 SO3 + SO2 + H2 O¼)2NaHSO3 and 2NaOH + SO2 ¼)Na2 SO3 + H2 O (ii) Inside the precipitation tank: 2NaHSO3 + CaO + H2 O¼)Na2 SO3 + CaSO3 ,2H2 O, and NaHSO3 + CaO¼)CaSO3 , 2H2 O + NaOH

(i) Inside the scrubber: Na2 SO3 + SO2 + H2 O¼)2NaHSO3

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and CaSO3 ,2H2 O + O2 ¼)CaSO4 ,2H2 O ðGypsumÞ (iii) Inside the regeneration tank: NaHSO3 + Na2 CO3 ¼)Na2 SO3 + NaHCO3 and NaHSO3 + NaHCO3 ¼)Na2 SO3 + H2 O + CO2 Due to some process loss in the sodium content in the form of CaSO3 and CaSO4 product, a small percentage of continuous make-up through Na2CO3 (soda) or Na2CO3, NaHCO3 (trona) is required to be added in the regeneration tank.

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FIG. 8.44 Schematic diagram of FGD with dual alkali-based wet scrubber and seawater scrubbing.

FIG. 8.45 Control loop schematic of SOx control with limestone absorber and gypsum recovery.

Boiler Control System Chapter

Spray Dry Scrubber The spray dry scrubber is made up of a semidry and a dry lime process. These processes have been developed as a competitive alternative to classical wet scrubber technology. The spray dry scrubber is next popular method with efficiency as good as that of a wet scrubber, if not better. The development in the process technology can render removal efficiencies of SOx up to 98% some manufacturers claim. For a FGD plant with a spray dry scrubber, unlike a wet scrubber, the ESP/dedusting equipment is located after this plant, which is a major layout criterion. This process make use of water-based sorbent containing lime (CaO) or milk of lime. The lime-based reagent is injected into a reactor vessel in the form of milk of lime (in the case of a lime spray dryer or semidry process) or humidified powder (in case of dry processes). The atomized form of the reagent, when it comes in touch with the hot flue gases, becomes dry and then the reaction takes place between the hydrated lime and SOx (mainly SO2) in the flue gases. The solid reaction product is collected by downstream dedusting equipment (ESP in case of a thermal power plant or a baghouse filter for a sinter plant, for example) and part of it is recirculated. Recirculation of this reaction product is made through the lime slurry preparation tank to reduce the bulk consumption of lime and hence the running cost of the project. The hydrated lime [Ca(OH)2], when it reacts with SO2, is converted into a mixture of calcium sulfate (gypsum) and sulfite. One of the many advantages of this process is that the requirement for a water treatment plant is eliminated. The in-duct sorbent injection method is also available as a comparatively less costly approach; it can be located more upstream in the flue gas path. This system does not require any extra space or a reactor vessel and can be easily applied to older or existing plants without a desulfurization facility. This system is also described as part of the sorbent injector process at a lower temperature. Additional activation of the sorbent may be achieved by spraying water to the flue gas at the downstream of the sorbent injection point where the sorbent is actually fed. The part of lime (CaO) that failed to make contact or react would now be converted to calcium hydroxide [Ca(OH)2], which is more reactive to SO2, letting the calcium sulfite part be further oxidized to calcium sulfate. The normal sulfur removal efficiencies of FGDs are on the order of 80%–85%. However, higher efficiencies can be attained if arrangements are made for water spraying after the sorbent injection point into the flue gas path (which reactivates the free sorbents in the flue gas), by spent sorbent recycling and by select optimized location of the sorbent injection point with respect to the temperature. Sodium carbonate (Na2CO3) can also be used as a sorbent where sodium sulfate (Na2SO4) would be the byproduct, which is soluble and stipulates special handling.

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That problem, along with the availability and cost factor, makes it less popular as a sorbent. Sorbent Injector The third method is known as a sorbent injector, but it is less popular and offers more or less 60–65% efficiency. In this process, dry sorbent such as limestone or hydrated lime [Ca(OH)2] is sprayed into the hot flue gases in the upper part of the furnace itself (high-temperature sorbent injector). Due to the reaction of sorbent and SO2, gypsum is produced and captured later in a fabric filter or electrostatic precipitator (ESP), along with fly ash. In this system, the gypsum cannot be used for commercial purposes as it would be mixed with fly ash and react with SOx and the calcium compound. The maximum temperature limit is around 1200°C and CaSO4 is not stable above around 1250°C in typical flue gases from a typical coal-fired SG plant. For the direct sorbent injection method, whether a low or a high temperature process, the efficiencies depend upon the approach temperature, the sorbent fineness, the injection point, and the recirculation of used sorbent. Seawater Scrubbing Other than scrubbing by alkaline chemical reagents, seawater, being a natural alkaline, can also be used as a sorbent, which absorbs SOx/SO2. Further oxidation by adding + oxygen promotes the formation of SO2 4 ions and free H + ions. The H ions then react with the carbonates present in the seawater to release CO2 gas. The reactions are SO2 + H2 O + O2 ¼)SO4 2 + H + and HCO3 + H + ¼)CO2 + H2 O This type of FGD system can be suitable for coastal regions. Fig. 8.44B, Schematic Diagram of FGD with Seawater Scrubbing, may be referenced. A part of hot seawater from the condenser outlet is used to scrub SOx/SO2 along with fly ash particles. In the water treatment plant, the pH of the scrubbing liquid at the outlet of the FGD unit needs to be adjusted before the same is sent back to the sea. Lime may be used for adjusting the pH of discharge seawater. 10.6.3.2

Controls of NOx

This control is very important as a part of the denitrification measure taken for the products of combustion, that is, flue gas. 10.6.3.2.1 Controls of NOx Through Process Control Loops The presence of the NOx level in the power plant can be reduced in many ways, as per the considerations set by different manufacturers. The main two basic ideas are: Reduced production of NOx through staging of air and/ or fuel (discussed in this chapter, clause no. 10.6.3.2.2) and through separate chemical process plant.

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10.6.3.2.2 Controls of NOx Through Separate Chemical Process Plant There are several methods of denitrification of flue gas other than control measures taken at the source. This is important because the generation of NOx cannot be fully avoided by protection at the source. NOx removal from flue gas through a separate chemical process plant is achieved by the following methods: (a) Dry process is more popular and needs discussion. (b) Wet process is a complicated process requiring wastewater treatment and hence is seldom used. Dry process may be of different types using the application of catalytic and noncatalytic reduction: (i) Selective catalytic reduction (SCR) by spraying ammonia (NH3) in the presence of a catalyst type depending on the flue gas temperature. (ii) Selective noncatalytic reduction (SNCR) by spraying ammonia/urea without a catalytic presence requiring a high temperature on the order of 800°C/1000°C. (iii) Nonselective catalytic reduction (NSCR) using the presence of multiple catalysts, namely platinum (Pt) with methane (CH4) or CO or H2. (iv) Catalytic cracking using platinum (Pt) as the catalyst. SCR, being the most widely used plant, is only discussed in this chapter. It is a means to convert NOx in the presence of various catalytic agents into nitrogen (N2) and water (H2O). Generally, SCR is located between the economizer and the air heater, and ammonia is injected before entering into a catalyst chamber. The approximate NOx reduction possibility is about 90% by this method. Aqueous or anhydrous ammonia, aqueous urea (also used as a reductant in the place of ammonia), etc., are added to the flue gas stream to remove NOx. Other possible reductants include cynuric acid and ammonium sulfate. Typical reactions are: 2NO2 + 4NH3 + O2 ¼ 3N2 + 6H2 O;4NO + 4NH3 + O2 ¼ 4N2 + 6H2 O;NO + NO2 + 2NH3 ¼ 2N2 + 3H2 O Secondary reactions may be 2SO2 + O2 ¼ 2SO3 ; 2NH3 + SO3 + H2 O ¼ ðNH4 Þ2 SO4 or NH3 + SO3 + H2 O ¼ ðNH4 ÞHSO4 CO2 is formed while using urea (instead of ammonia) as per the reaction below: 4NO + 2ðNH2 Þ2 CO + O2 ¼ 4N2 + 4H2 O + 2CO2 The ideal reaction has an optimal temperature range between 360°C and 450°C, but can operate at a further lower range from 230°C to 450°C requiring a longer reaction/residence time. The minimum effective temperature depends on the various fuels, gas constituents, and catalyst type/geometry.

10.6.3.2.3 Catalysts Used for SCR Operation SCR catalysts are manufactured from various ceramic materials used as a support or carrier, for example, titanium or aluminum oxides whereas active catalytic components are usually base metal oxides of vanadium, tungsten, etc., or zeolites. Precious metals such as platinum, etc., are also used as catalysts (clause no. 10.6.3.2.2 of this chapter). Usage of base metal catalysts such as vanadium and tungsten is not suitable at higher temperatures because of the lack of high thermal durability; however, they are popular for their lower operating costs. Most of the industrial and utility boiler applications can well be covered by the temperature ranges offered by them. Zeolite oxides, on the contrary, are capable of operating at substantially higher temperature (continuous operating range at 630°C) than base metal catalysts with maximum short temperature withstanding capacity up to 850°C). The shape/geometry of the catalysts is considered the influential factor for SCR system design. They are available in various forms/shapes such as granules, grids, honeycombs, plates, etc. The catalysts characteristically have their own advantages and disadvantages. For example, the honeycomb configurations are smaller than plates and less expensive, but they have higher pressure drops and are susceptible to plugging more often and more easily compared to plates. Plate catalysts are much larger in size and more expensive. The instrumentation and controls involved here are not too many and can be integrated with the main DCS. In order to keep excess NH3 (being harmful to human life) within limits, the NH3 needs to be monitored and controlled. The catalyst bed loss or the differential pressure loss across the catalytic chamber also requires close monitoring.

10.6.4 Combined SOx-NOx Removal 10.6.4.1 SOx-NOx Removal by Fluidized Bed Copper Oxide Process (Fig. 8.46) This process is an advanced technology that provides for the simultaneous control of SOx and NOx. The copper oxide process offers a number of advantages over conventional approaches to SOx and NOx control, as discussed above. The same are listed below: (i) The combined removal of SOx and NOx is accomplished in a single reactor vessel. (ii) The system is regenerative as far as copper oxide is concerned. (iii) The process byproduct is a saleable form of sulfur (e.g., sulfuric acid). Currently, this type of FGD is regarded as a potential type of NOx control system also though during the initial period the aim was to eliminate SOx only as that was considered as most important pollutant.

Boiler Control System Chapter

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FIG. 8.46 Schematic diagram of SOx NOx control with fluidized bed copper oxide process.

There are three basic compartments envisaged in this system: the absorber, heater, and regenerator. In the absorber, the sorbent is made fluidized by the flue gas injected from the bottom. The copper, as copper oxide, reacts with sulfur oxide to produce copper sulfate at about 400°C. The reactions are: 2CuO + 2SO2 + O2 ¼)2CuSO4 and CuO + SO3 ¼)ðCuSO4 Þ Ammonia (NH3) is injected into the flue gas or premixed before it enters the absorber. In the absorber, it reacts with nitrogen oxides, with the copper sulfate acting as the catalyst. The reactions: 4NO + 4NH3 + O2 ¼)4N2 + 6H2 O and 2NO2 + 4NH3 + O2 ¼)3N2 + 6H2 O These are exothermic reactions and the heat generated could be utilized through the flue gas in the air preheater located next to this plant. This process then needs methane (CH4). Part of it is burnt in a combustor and the hot gas is sent to the two-stage heater vessel. Copper sulfate sorbent is heated typically at

about 500°C. Hot copper sulfate is then allowed to enter a moving bed regenerator from the top, whereas the methane is introduced at the bottom of the reactor. The copper sulfate when coming into contact with methane at
500°C is reduced to Cu, releasing SO2. There may be some copper oxide (CuO) contained in the sorbent entering the regenerator. This would react readily with the SO2 in the exiting off-gas/exhaust gas to form copper sulfite (CuSO3). To summarize, it may be stated that inside the regenerator, the sorbent may consist of copper sulfate, a small amount of copper oxide, and copper sulfite. The reactions are CuSO4 + CH4 ¼)Cu + SO2 + CO2 + H2 O, CuSO3 + CH4 ¼)Cu + SO2 + CO2 + H2 O and CuO + CH4 ¼)Cu + CO2 + H2 O The concentrated SO2 can be used to produce sulfuric acid, similar to the Wellman-Lord process. The Cu sorbent is transported back to the fluidized bed using air, during which it is oxidized to CuO as per the following reaction:

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(A)

(E)

(B)

(C) (D)

(F)

FIG. 8.47 Low NOx burner over fire air damper reburning and SNCR for NOx control.

2Cu + O2 ¼)CuO and 2CuSO3 + O2 ¼)2CuSO4 (Copper sulfite if any is also oxidized to the basic sorbent form). The exhaust product gas/offgas, that is, SO2 from the regenerator may also be utilized for recovery of sulfur in its elemental form in a separate place called the section plant. At this plant, the exhaust gas containing some methane is then converted as per the reaction: 2CH4 + 3SO2 ¼)S + 2H2 S + 2CO2 + 2H2 O and CH4 + 2SO2 ¼)2S + CO2 + 2H2 O Hydrogen sulfide (H2S) gas is also converted to yield elemental sulfur by the following reaction:

has not become very popular due to the unavailability of more improved qualities of accessories such as an electron gun vis-a-vis an accelerator, etc., suitable for continuous operation in an industrial environment. The application of the electron beam is meant for encouraging the oxidation process of sulfur dioxide to sulfur compounds. Ammonia injection makes it react with sulfur compounds to form ammonium sulfate. This byproduct is known for being used as a nitrogenous fertilizer after further processing to produce ammonium sulfate crystals through proper separation, drying, and screening before bagging or bulk loading. The ammonia injection also helps in lowering the presence of nitrogen oxides in the flue gas, as described above.

2 2S + SO2 ¼)3S + 2ðH2 OÞ 10.6.4.2 SOx-NOx Removal Through Gas phase Oxidation/Ammonia Injection This is a new technology used for both denitrification and desulfurization of flue gas. It is a technology involving a radiation chemistry process where the physical effects of radiation are used to cause a desired reaction. In this process, an intense beam of electrons is fired into the flue gas with simultaneous injection of ammonia. This system

10.7

Fuel Oil Pressure Control

General Fuel oil has been associated as a supporting fuel and may be of any type such as heavy furnace oil (HFO), heavy petroleum stock (HPS), low sulfur high stock (LSHS), etc. As already discussed in Section 4 of this chapter, it is normally used in any of the steam-generating plants for start up, low load operation, and coal flame stabilization at all

Boiler Control System Chapter

loads if required. These oils need heating before being burned. For example, the flash points are 66°C for HFO and HPS and 75°C for LSHS. LDO firing, if provided, does not need preheating for burning. The fuel oil is drawn from the HFO storage tank(s) by fuel oil pressurizing pumps and pumped through steam oil heaters. The oil, duly pressurized and heated, reaches near the boiler front in a ring main arrangement from which the exact requirement of oil is taken off by the oil burners. The extra oil not required for firing is returned back through the recirculation line to the storage tanks. The ring main oil pressure is maintained to the required set value by means of a control valve provided in a separate recirculation line near the pumps. Oil temperature is controlled by regulating steam flow to the fuel oil heaters. The LDO firing system is provided to facilitate starting of units when no auxiliary steam or auxiliary boiler is available from an external source. The LDO firing system shall also be used for cold start-up of steam generators and for flushing of HFO lines. It may be noted that the basic scheme for an LDO system is the same as discussed above for a fuel oil system, except that the suction for the LDO pressuring pumps is taken from the LDO tanks and there are no heating requirements.

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The pressure-control valve is located in another recirculation line after the fuel oil pumps/heaters so as to maintain a fixed fuel oil discharge header pressure with the capacity as required when no burner is operating when it has to allow all the oil from the pump discharge back to the tank. The fuel oil pressure is around 15–25 kg/cm2, depending on the type/ size of the burners, the distance and height of the remotest burner, etc.

10.7.3 Control Loop Description (Fig. 8.48A) The schematic representation depicts the control strategy as the direct, single, and simple type.

10.7.4 Control Loop (HFO/LFO Recirculation Control) The measured/process variable is compared with a fixed set value to form the error signal. The controller output is the position demand signal of a control valve in the recirculation line. When there will be lees demand, the recirculation will open more and vice versa. These pressure transmitters are normally the sealed diaphragm type to avoid chocking or wax formation/deposition inside the sensor part. The impulse line up to the transmitter would, however, be steam traced or electrically heated.

10.7.1 Objective There are two control loops and the objective of these control loops is to maintain the fuel oil header pressure at the pump discharge and at the burner front ring main where all the burners get their oil supply. It is very important that these header pressures are maintained at a fairly constant value and each burner gets more/less the same quantity of oil when the burner valves (open/close type) are fully open. Figs. 2.9 and 8.48A and B may be referenced in this regard.

10.7.2 Discussion The very nature of fuel oil (HFO, HPS, or LSHS), being a highly viscous liquid, requires that the temperature must always be kept around a value necessary for maintaining sufficient fluid mobility. Another important requirement is to provide recirculation facility of the oil line from the burner front to the oil tank itself so that the oil viscosity is maintained through steam tracing or lagging with an electrical heating arrangement. This line is popularly called a long recirculation line, which covers the entire oil line while the unit is operating. There is one recirculation line that enables oil back to the oil tank much before the burner front and after the fuel oil pumps/heaters. This line is known as the short recirculation line, and it covers a smaller part of the oil line while the unit is not operating, that is, on a long shut down. This valve remains 10% open even in a running unit to ensure fluid mobility.

10.7.5 Control Loop HFO/LFO Flow Control at Boiler Front (Fig. 8.48B) The fuel oil pressure is measured by a pressure transmitter with sufficient redundancy and at the appropriate location near the burner front to get a representative measurement. The measuring point is important so that the highest and remotest burner gets sufficient pressure to cater to the requirement. The type and installation of the pressure transmitter are discussed above. The set point is sent through a “max” circuit to ensure a minimum header pressure at the boiler front. The error created by the set point and the actual pressure is sent to the PI controller to regulate the valves to cater to the HFO flow demand. When the opening of the valve is <2% (i.e., closed), signal is sent to FSSS to close the trip valve for positive isolation. The loop description and drawing are given for HFO only, but will be similar for LDO.

11

HP-LP BYPASS SYSTEM

General There are situations that arise in a large power plant where the turbo generator (TG) sets are subject to undergoing extreme operating conditions such as a sudden load throw off, a full load trip out, or even a planned shutdown for a short span of time. In all conditions, the TG set is expected to run on the house load/low load or in case of a

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Power Plant Instrumentation and Control Handbook

(A)

(B)

FIG. 8.48 Boiler oil pressure control.

turbine trip/shut down, the open generator circuit breaker, and to restart as quickly as possible so that revenue earning is continued. The design trend for the TG set has long been that the units must be suitable with the systems that enable them to run on house load operation. It may not be out of the way to mention that by house load operation, the unit can supply its own auxiliaries’ electrical load and need not depend on the external power supply from the grid supplied by the other connected units. When there is a blackout, that is, a full load tripping has taken place from the entire grid failure, the house load operation facility keeps the boiler running and the TG set ready for further loading at the earliest. All these above-mentioned facilities are obtainable if the unit is designed for and supplied with an HP and LP

bypass system having sufficient steam handling capacity of 60% or even 100%, depending on many influencing factors. Many of the standard TG systems, HP and LP bypass is essential for its start-up and shutdown that is, TG cannot be started (say heat soaking) without HP and LP bypass. In some system designs, parallel operation of the bypass is also allowed. The most important function of the steam turbine bypass system is practically to simulate the expansion and heat transfer process that normally takes place inside the operating steam turbine. In other words, the HP-LP bypass system provides an alternative route of the steam line from the boiler to the condenser. By doing so, the steam

Boiler Control System Chapter

generation is almost uninterrupted or artificially loaded when there is no operating load (start-up), turbine trip, or a part load on the turbine. This system facilitates faster plant start-ups, that is, raising the steam parameters to suit the turbine requirements as needed by different kinds of startups. The most advantageous condition of the HP-LP Bypass system is to implement a hot start-up, which means a minimum life expenditure of the turbine components and auxiliaries with the overall advantage of the boiler, turbine, and generator’s increased availability. The turbine bypass system has manifold applications as it is suitable for handling almost all the possible start-up conditions such as cold start up, warm start-up, and hot restart as well as turbine shutdowns and disturbed situations such as load rejections and unit trips. In any case, bypass operation always calls for a loss of energy but this may be traded off by the time and money savings to meet the emergency and/or long start-up time of the boiler. The HPBP system, during situations mentioned above, connects the main steam to the cold reheat line at matching pressure and temperature conditions through the HPBP valve, bypassing the HPT. The LP bypass connects the hot reheat line to the condenser through the low-pressure bypass (LPBP) valve, bypassing the IPT and LPT with suitable steam conditioning. In ultrasupercritical plants, there may be HP, IP, and LP bypasses, as there may be two stages of reheating and IPTs. However, all these systems operate in tandem. The system is designed to incorporate the controls of the parameters such as pressure, temperature, and steam flow as they should have been at the turbine entry and exhaust points during the prevailing running condition of the turbine before the HP-LP bypass comes into action. It would have then been steered to the desired condition suitable for the purpose it is used for at that moment. Normally, the HPLP bypass system does not directly interface with the turbine control and supervisory system, but is set to maintain all the above steam parameters by directly carrying out process measurements to tackle the situations for which it is deployed. The overall benefits that may be available by installing an HP-LP bypass system are summarized as follows: (i) The unit can be started even if there is a grid failure and consequent blackout. (ii) Safety valve pop-up situations are less/rare with an efficient HP-LP bypass system. (iii) The demineralized water requirement is less during start-up/trip-out conditions. (iv) Less rate of pressure rise in boiler under trip-out condition. (v) House load operation is practicable.

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For medium and larger capacity HP-LP bypass systems, the steam flow measurement through the HPBP requires consideration for calculating the total steam flow and the corresponding feed water flow requirement to develop the control strategy toward the boiler control systems where parallel operation is allowed. This is especially required where the steam flow to the turbine is measured by the characterized turbine first-stage pressure or if the flow sensor is installed after the bypass connection. The signal from the flow sensor at the HP bypass line or a characterized bypass valve position indication may be used to measure the bypass steam flow. On the other hand, if the steam flow is measured before the HP bypass connection, then separate HP bypass flow measurements can be eliminated. The bypass system itself along with the control system is normally designed in a way that flow/pressure/temperature fluctuations are reduced to a possible minimum for avoiding inadvertent effects on the performance of other associated systems. The bypass system, especially the LPBP system design, must incorporate and ensure the proper conditioning of the bypassed steam while entering the condenser. It is extremely important that the steam conditioning is guaranteed to the level best against thermal or vibration damage to the sensitive heat transfer surfaces and structures within the condenser. European boiler codes, unlike American boiler codes, allow omitting the conventional safety valves and operating the system with the HP bypass valves only.

11.1

Objective

The objective of the control loops of the HP-LP bypass system is to maintain the steam pressure, temperature, and flow as demanded by the situation at suitable points.

11.1.1 High-Pressure Bypass System The HP bypass system is designed to accomplish the following system requirements: (a) Boiler main steam pressure control. (b) Temperature and flow control of steam to match the CRH condition to cool the boiler reheater elements. (c) Steam flow control in the MS line to cool the final superheater in case of sliding pressure operation. For example, in an OT boiler, the steam temperature control is highly dependent on the feed water flow and firing rate. The effect of a firing rate reduction could take more while the feed rate has to be maintained to cool the superheater, resulting in more steam than that is required so the HPBP takes care of the extra steam.

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11.1.2 Low-Pressure Bypass System The basic function of an LP bypass valve is mainly for the protection of the condenser. The system is designed to condition reheat steam acceptable to the condenser. This obviously calls for a large valve (the FCE) due to the enormous increase in the specific volume of the steam to suit the subatmospheric pressure at the condenser. The LP bypass system is designed to accomplish the following system requirements: (a) Control the pressure of the steam after bypassing the HP turbine, or, in other words, the HRH steam pressure according to the loading of the turbine. The temperature and flow control of steam through the CRH line to cool the reheater elements. In cases, condenser pressure/ temperature is high then LP bypass dumping is stopped/vented otherwise followed by firing rate reduction).

11.2

Discussion

Turbine bypass control valves have long been associated with demanding process conditions. In controlling the high-pressure/temperature steam of this critical service, the valves necessarily require a sophisticated valve design with powerful actuators that would enable full travel time in 2 s or less. They also are supposed to have the quality of a high degree of closure, normally with a leakage rating of Class V or better. Noise immunity is extremely important with stringent noise restrictions. For larger plants and supercritical plants, major suppliers recommend having in-body desuperheaters with a special design for better performance. Regarding HPLP bypass valve actuators, hydraulic power units are preferred in Europe, whereas in the United States, pneumatic actuators are preferred due to their relatively low cost.

11.2.1 System Capacity There are a number of possibilities and influencing factors to determine the capacity of the bypass system. The bypass system capacity to accomplish the previously mentioned functions is as follows: (i) Bypass capacity of 15% only of maximum continuous rated (MCR) flow at valves wide open enables the unit for matching the steam-to-turbine metal temperatures with a reduction of the start-up time by about 30 min. (ii) Bypass capacity of 40% of MCR flow at valves wide open can cope with the transient or disturbed conditions of minor nature is taken for granted to be enough. Larger capacity may also be considered for handling more critical situations. (iii) Bypass capacity of 100% of MCR flow at valves wide open takes care of the situation with the boiler running

at full load and the occurrence of any untoward situations such as a turbine or generator trip and would not let the safety valves blow. (iv) The bypass systems with suitable capacity can bring down the steam generation in the boiler in 10 min or less to a house load capacity of approximately 10%– 20% without creating excessive temperature gradients. In that case, some manufacturers recommend 60% HPBP and 100% LPBP systems. The steam flow capacity of the bypass system is also influenced by a number of other factors: (a) Condenser capacity, internal arrangements, and materials. (b) Turbine rotor diameter. (c) Start-up, shut down, and loading and unloading procedures and requirements. (d) Safety considerations related to SH, RH, and condenser. (e) Reheat pressure for turbine start. (f) Number of warm starts, hot starts, and requirements for house load operation. (g) Cost consideration.

11.2.2 Different Mode of Starts Through Bypass Systems The following modes of operations are possible, which justifies the best use of bypass systems after making a proper size and design selection. 11.2.2.1 Cold Start The HP-LP bypass system permits improved operating condition of the furnace, the primary and secondary superheaters and reheaters, and the main and reheater steam lines. The system as a whole improves the quality of the steam generated by the boiler before starting the turbine; this reduces the start-up times significantly. The turbine can be started from the turning gear and can reach the rated speed in 15–30 min, provided temperatures at different points of the turbine rotor are proper and following the turbine manufacturer’s temperature gradients as per the thermal stress evaluator (TSE) guidelines. The bypass operation may take approximately 2.5–3.5 h. The steam flow through the superheater and reheater guaranties the tube cooling in an effective way and facilitates the boiler for going ahead with a higher furnace firing rate. 11.2.2.1.1 Role of HPBP System During Cold Start (Fig. 8.52) Step (i) During cold start, the bypass valve is kept open a crack or open up to the admissible minimum position to allow steam flow through the SH and RH banks as soon as the furnace starts firing.

Boiler Control System Chapter

Step (ii) After generation of sufficient steam capable of exerting the minimum required pressure, the bypass valve begins to open as required by the controller to maintain steam pressure to a certain value. Step (iii) Valve position reaching at the preassigned value sufficient to initiate pressure build up through a ramp commences with more production of steam through more or less a fixed opening of the valve. This step allows more steam in pressure-building activity but with a gradient within the permissible limit by the system. Step (iv) Steam pressure reaches the value desirable for preparing the turbine start-ups, and the bypass valve opens further to maintain the steam pressure at a constant value. Step (v) After a time, the turbine is ready to be synchronized with a small load and the bypass valve would start closing no sooner than when the turbine takes further loading. Step (vi) Bypass valve would be fully closed after a predetermined load is delivered by the TG set. 11.2.2.1.2 Role of LPBP System During Cold Start During cold start, the LP bypass valve can be operated in two ways, as indicated below: (i) The valve would remain closed to allow the reheat pressure to develop and then start opening to control the RH steam pressure as per the set point generated. (ii) The valve would act similarly to the HPBP system to develop pressure in a controlled manner. 11.2.2.2 Warm Start The benefits as available from the bypass systems as mentioned in the above Section 11.2.2.1 for cold start are also applicable to this mode. The only difference is the initial casing temperature of the HP turbine is usually above 100°C. However, the bypass systems enable the start-up operation to run in an efficient way through corelating the steam temperatures to the corresponding metal temperatures under all speed conditions. 11.2.2.3

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the metal temperatures of the thick and heavy turbine parts. The incorporation of a hot start facility in the bypass systems enables the unit to shrug off the unnecessary cooling down and rewarming procedures. 11.2.2.4 Quick Start After Full Load (or Partial Load) Rejection The duty of the bypass system calls for an immediate opening of the bypass control valves in the case of a partial- or full-load rejection. The bypass control systems open the bypass valves to the same degree as the turbine control valves were before being closed, that is, the occurrence of unacceptable conditions. Protective systems should be provided to trip the boiler when the HP/LP bypass valves fail to open and when an insufficient cooling steam flow passes through the SH/ RH. Adequate safety measures for condenser protection are essential during LP bypass operation.

11.3 Control Loop Description (Figs. 8.49 and 8.50) The control schematics depict the strategy (a typical 250 MWTPS having a drum boiler) of the normal load operation and not the start-up, which is usually controlled manually.

11.3.1 Measurement of Different Parameters The following parameters are measured with sufficient redundancy and voting before actual use in the control loops. 11.3.1.1 Measurements for HP Bypass Control Includes MS header pressure near the turbine inlet, steam temperature at the HP bypass valve outlet for desuperheater spray water flow control to maintain the outlet steam temperature at the desired level, and desuperheater spray water pressure to bring down the take off feed water pressure to match the HRH/CRH steam pressure level.

Hot Start

Many of the advantages mentioned in earlier sections are applicable to this mode of operation as well. Sometimes the turbine-generator (TG) set experiences tripping out to save the set from disturbances of a minor nature. These tripping causes can be rectified with a comparatively low time span and then the unit becomes very much suitable for a hot restart. The bypass systems are designed to enable the unit start-up at the earliest possible time through close watch, and then by matching the steam temperature with

11.3.1.2 (i) (ii) (iii) (iv)

Measurements for LP Bypass Control

Turbine first-stage steam pressure. Reheat outlet steam temperature. Reheat outlet steam pressure. LP bypass steam temperature at the desuperheater outlet. (v) Position signal for both the LP bypass and spray control valve (vi) LP spray water pressure.

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FIG. 8.49 HP bypass pressure and temperature control.

Boiler Control System Chapter

FIG. 8.50 LP bypass control pressure and temperature control.

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11.3.2 The Control Loop Strategy The FCEs of these control strategies incorporate the following items: (i) HP and LP bypass pressure-control valves. (ii) HP and LP bypass spray water (temperature) control valves. (iii) Spray water pressure control valve for HP bypass system.

11.3.2.1

HP Bypass Control

11.3.2.1.1 HPBP Pressure Control The control strategy is based on a single-element control concept. The selected signal of the main steam pressure near the turbine outlet becomes the measured/process variable. For a fixed main steam pressure control system, the HPBP set point is also a fixed value, which is normally higher than the master pressure control set point with a slight margin (
5.0 kg/ cm2). For a variable set point for a sliding pressure controlled system, the set point is derived as characterized from the load index, such as the main steam flow or the first-stage pressure, and then the bias for the margin is added. After the selection, the set point signal is passed through a maximum and a minimum selector. The steam pressure set point is thus limited within a minimum and maximum value and then passed through a tracking integrator (TRI) to have a ramped and smooth output to become the final set point so as to prevent process upsets. The maximum value of the integrating gradient is limited. In fact, the operating gradient is a very low value so that the instantaneous set value becomes lower than the main steam pressure in case of a sudden upset. For example, when there is a large load rejection, the steam pressure starts rising and if it becomes higher than the set point (with margin), the bypass valve opens as per the controller output command and tries to reduce the steam pressure. The set value for a variable pressure system would readjust its value as per the new load and the bypass valve would remain open up to a certain value until the steam pressure matches. The firing rate is then modified as per the load and the steam pressure is also readjusted so as to gradually close the bypass valve to bring back the normal operating condition. There is another control loop strategy applicable to both fixed and variable pressure systems that is also shown in the above drawing as an alternative. Here, the main steam pressure itself is utilized as the set point after adding the bias for margin DP and passes through TRI to generate the final set point. The tracking integrator plays the vital role as described above. The TRI would change its output at a very slow rate. Whenever there would be large load throw off, the MS pressure would shoot up at a very fast rate while the set point increased at a slower rate, which causes the HPBP valve to open to arrest the high pressure excursion. When the load

and heat input stabilize, the bypass valve would again close. In a turbine trip, the bypass valve would open and the pressure control set point would be the minimum value, for example, the pressure required for a hot start-up. The rest of the system is the same as before. 11.3.2.1.2 HPBP Temperature Control (by Spray Water Valve) The control strategy is based on a very simple single-element control concept. The selected signal of steam temperature at the HP turbine bypass outlet becomes the measured/process variable with a fixed set point. The difference between the two signals form the error signal of the control loop and the controller (PID) output is supplemented with a feed forward signal from the HPBP valve position to get an advanced sense of the process condition. If measured separately, the bypass steam flow itself may be used as a feed forward signal for the temperature control system. Otherwise, the suitably characterized bypass valve position indexed by the steam pressure may be taken as an indicative signal of this steam flow. The combined signal is used to regulate the high-pressure desuperheater spray water control valve. 11.3.2.1.3 HPBP Spray Water Pressure Control The header pressure of the spray water should be maintained at a desired value. For this, there is a separate pressure control loop, as shown in Fig. 8.49. Here, the error generated by the set point and the measured variable (pressure at the spray water valve inlet) is fed to a controller, the output of which regulates the opening of the HPBP spray water pressure-control valve. There are certain interlocked conditions other than the fast opening and fast closing criteria indicated in clause no. 11.3.2.3.1; they are indicated as follows:

▪ Valve is not permitted to open at the HPBP spray water pressure low. ▪ Valve is not permitted to open when the HPBP spray block valve is not fully open. 11.3.2.2 LP Bypass Control 11.3.2.2.1 LPBP Pressure Control The control strategy is based on a single-element control concept. The selected signal of the reheater outlet steam pressure at the turbine inlet (HRH) becomes the measured/process variable. The set point is of variable value, which is obtained from the characterized turbine first-stage pressure. The relation between the turbine first-stage pressure and the HP turbine exhaust, that is, the cold reheat (CRH) steam pressure, is exploited with some consideration of the line pressure loss in the reheater circuit determines the HRH set value. When the turbine trips and/or during start-up, there will not be any first-stage pressure to act as the set point. So, the HPBP valve position (in case of more than one HPBP pressure control valve, the average valve positions)

Boiler Control System Chapter

is taken as the set point through a selector circuit, as shown in the loop. The difference between the two signals forms the error signal of the control loop and the controller (PID) output is used to regulate the high-pressure control valve. 11.3.2.2.2 LPBP Temperature Control (by Spray Water Valve) Efficient operation of any desuperheater calls for the injection of hot water, essentially to be at a temperature near the saturation temperature of the steam being cooled. It ensures that mainly the latent heat is extracted from the steam to evaporate the injected water. This design criteria assumes minimum suspension time experienced by the water particles in the steam path so as to make certain that the injection water is completely evaporated. Complete evaporation must be attained before the first pipe bend to avoid the impinging of water particles on the inside walls of the pipes. The desuperheater performance depends on the degree of atomization of the injected water and the mixing with the steam. Proper and speedy evaporation depends on the proper location and direction of the spray water jet as well. The control strategy (Fig. 8.50A) for LP bypass temperature control is based on the ISA recommended simple single-element control concept. The selected signal of the steam temperature at the outlet of the LP turbine bypass becomes the measured/process variable. The set point is calculated essentially from the steam mass flow and steam condition. Normally, the steam mass flow online measurement is not done in this large diameter pipe, but in turn is calculated as a function of the bypass valve position duly characterized to the steam flow and the corresponding steam conditions. The difference between the two signals forms the error signal of the control loop and the controller (PID) output regulates the desuperheater spray water control valve lift position. This determines the requisite quantity of injection water flow that provides the guideline for the LPBP downstream steam condition. An alternative loop (Fig. 8.50B) suggests making the calculated unit enthalpy from the LPBP valve outlet temperature and the pressure multiplied by the calculated steam mass flow as the measured variable. The set point is the manually adjustable enthalpy, as desired. This loop has been developed to take into consideration that steam conditions after the LP bypass desuperheater spray are very close to or at the saturation condition; the temperature after the desuperheater is not recommended to be used as a control signal. The feed forward signal is incorporated from changes in the LPBP valve position. Another alternative loop (Fig. 8.50C) avoiding LPBP temperature measurement incorporates the heat balance method to determine the requisite quantity of spray or cooling water to maintain the enthalpy in relation tothe condenser outlet temperature. The heat loss by the steam is equal to the heat gained by the water when mixed to form

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a saturated condition. Heat lost by steam is the product of steam quantity and the difference between enthalpy at the LPBP inlet and the condenser inlet; heat gained by water is the product of water quantity and the difference between enthalpy at the condenser inlet and the spray water. The enthalpy is taken from the steam table at process temperature and pressure. The desired water quantity is the ratio of total heat lost by steam and enthalpy difference from the water side, which becomes the set point. Water quantity is the measured variable and the controller output regulates the spray water valve lift. As has already been discussed, the LP bypass is basically provided for the protection of the condenser. As such, some condenser manufacturers stipulate the following guidelines in addition to the above control philosophy for start-up as well as intermittent and continuous control to maintain the LP bypass downstream steam temperature conditioning: (i) Enthalpy restriction Steam entering the condenser with enthalpy >670– 680 kcal/kg is restricted; in the case of sudden high flow steam dumps, the enthalpy is recommended to be restricted to 660 kcal/kg. In certain cases, steam admission to the condenser with enthalpy >680 kcal/ kg is also considered where the specific conditions of unit operation suggest it. (ii) Pressure restriction The maximum pressure of steam admission to the condenser is restricted to a limit value of 16 kg/cm2 (g), mainly applicable for the dump condenser. To accommodate the above guidelines, temperature and pressure at a suitable point are measured to calculate the enthalpy of the entering steam; this is considered as a measured/process variable. An appropriate set value as depicted above is provided for generating the control error. Also, a controller output is added to the conditioned steam flow derived from the LP bypass pressure control valve position to form the demand for the LPBP spray control valve position. Interlocked conditions other than the fast opening/ closing criteria (indicated in clause no. 11.3.2.3.2) are as follows: The valve is not permitted to open for any of the following conditions. (i) (ii) (iii) (iv) (v)

Insufficient desuperheater spray water pressure. Block valve is not fully open. High condenser pressure. High condenser temperature. High condenser hot well level.

11.3.2.3

HP LP Bypass Interlocks (Fig. 8.51)

11.3.2.3.1 HP Bypass Interlock (Fig. 8.51A) l Fast opening criteria: Under these severe conditions, it is required that the HPBP valve and the associated spray

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(B) FIG. 8.51 HP LP bypass interlock conditions and control.

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FIG. 8.52 Cold start-up: Graph of different parameters with respect to HPBP valve position.

l

valve and block valves shall open fully for a period to allow the HP bypass to dump the steam. During this time, the spray control pressure valve shall be auto so that suitable pressure is maintained. Suitable signals are sent to the LPBP system to enable its fast opening (Typically, these conditions are shown as signal output and the initiating criteria listed below as the input signal—applicable for all cases): o. Load shedding relay is operated. o. Generator circuit breaker is open. o. Turbine trip acted. o. High load dumping. o. MS pressure at/near turbine is very high. o. HPBP valve is almost open (to ensure full open). Force/fast closing criteria: o. The PBP valve shall close under any of the following conditions: ▪ Fast closing criteria from LPBP (discussed in clause no. 11.3.2.3.2). ▪ HPBP spray water pressure low. ▪ HPBP spray block valve not fully open. ▪ Steam temperature after HPBP valve is The o. The HPBP spray control valve shall close under all the above conditions, provided the associated HPBP valve is closed (<2% open).

o. The HPBP spray pressure control valve shall close when the HPBP spray control valve is closed, provided fast opening criteria do not exist.

11.3.2.3.2 LP Bypass Interlock (Fig. 8.51B) Fast closing criteria: It is necessary for condenser protection against conditions that would tend to increase condenser temperature. o. The LPBP valve shall be closed under following condition: ▪ Condenser temperature is very high. ▪ Condenser pressure is very high. ▪ LPBP spray water temperature is very high. ▪ LPBP spray water pressure is low. ▪ LPBP spray block valve is not fully open. o. The LPBP spray valve shall be closed under the conditions stated above, provided the associated LPBP valve is closed (<2% open). l Force/fast closing criteria: o. The HPBP valve shall close under any of the following conditions: ▪ Fast closing criteria from LPBP, as discussed in clause no. 11.3.2.3.2. ▪ HPBP spray water pressure is low. l

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▪ HPBP spray water pressure is low. ▪ HPBP spray block valve is not fully open. ▪ HPBP valve outlet steam temperature is very high. o. The HPBP spray control valve shall close under all the above conditions, provided the associated HPBP valve is closed (<2% open) o. The HPBP spray pressure control valve shall close when the HPBP spray control valve is closed and no fast opening criteria exist. Fast opening criteria: Under these severe conditions, it is required that the LPBP shall open fast under fast opening conditions of the HPBP, provided there is no fast closing criteria or very high steam temperature after the LPBP valve. These will cause all LPBP pressure and spray valves and associated block valves to open.

12 BOILER OLCS: INTRODUCTION TO INTERLOCK AND PROTECTION OF BOILER BMS, SADC, SB CONTROL General The closed-loop control system (CLCS) always takes feedback from the process for which it is employed and readjusts the control output to get the desired process parameter. For more accurate or adaptive control, even the output signal is measured and feedback to the controller as another input of the control system. The CLCS is widely regarded as a regulatory part of the total control system and is accommodated in the auto control loops. An open-loop control (OLC), on the contrary, does not utilize the same (feedback) and hence is also called a nonfeedback control. As the OLC does not normally utilize the feedback signal in computing the output, it also does not take care whether the desired condition has been achieved in the input. This also means that the control system is insensitive about the output without monitoring the processes status that it is controlling. As corollaries, it can be said that the open-loop system normally does not compensate for the disturbances in the system and at the same time cannot correct, unlike closed-loop control, any errors that might be generated while issuing the output. However, for a sequential control system, the feedback signals are checked before proceeding to the next step. The OLC is most suited for the following applications: (i) Simple processes where feedback is not so critical or control within a moderate band is acceptable and cost toward the CLCS can be avoided. (ii) A process of the nature where the control output mainly depends on the proper decision and assessment of the human operator and where automation may lead to wasting energies of different forms.

(iii) A process related to implementation of sequential or safety (protection)/interlocking logic systems where process measurement feedback signals are not required; for sequential logic, status feedback signals are required to proceed to the next step only. In general, OLCS is the interlock/protection part of the total control system with a separate entity. It may also be noted that this system is designed to automate the required operator actions during an abnormal event or any change in operating status of the plant, for example, a trip, startup, shutdown etc. All these above conditions necessitate the immediate and accurate handling/management of the situations, either through operator action or by some other means. It has been experienced and observed through experiments that the human response to emergencies is not beyond question. There is every possibility of erroneous operator action either toward making a judicious decision or timely intervention. These untoward situations can well be tackled if the actions are envisaged in logic form and then implemented through state-of-the-art technology, thereby avoiding damage to humans, the environment, and equipment. Such damage could result in more capital cost, loss of production due to a long shutdown time, and/ultimately loss of revenue; this justifies the application of a separate interlock/protection system. The separation of the interlock/protection processing part from the regulatory control system has always been the center of discussion in control and instrumentation packages for thermal power plants. In a large power plant, the control systems are also large and complex as well as being developed with state-of-the-art technology that has sophisticated software and hardware. Though there are several signals required to be exchanged between the two systems, that is, between CLCS and OLCS, the same can be done through hardware or wet/soft signals without jeopardizing the resultant security and reliability. The logic must also differentiate between the safety protection part and the interlock part of the plant requirements based on the degree of possible hazards, including personnel injury as well as damage to the plant equipment and the environment. The degree of redundancy in the logic processing area is also determined by the above criteria for the selection of hardware/software.

12.1

Boiler OLCS

The boiler OLCS mainly comprises different sequential or safety (protection)/interlocking logics covering the following categories: (i) The equipment, namely ID fans, FD fans, PA fans, boiler water circulating pumps, BF pumps (if in a boiler package), seal air fans, scanner air fans, mill/ pulverizer motors, feeder motors, and lubricating oil

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pumps (LOPs) of all the drive motors needing lube oil without grease lubrication (covered in the BMS/ furnace supervisory and safeguard system (FSSS) or a separate OLCS). (ii) The on/off dampers and valves (motor-operated and/ or solenoid-operated) related to air, oil, steam lines, etc. (Covered in BMS/FSSS). (iii) Logic systems for boiler tripping, purging/firing, starting, shutdown, etc. (covered in BMS/FSSS).

(ii) Inlet/outlet dampers/valves, hydraulic coupling scoop tube, etc., open or closed as per the requirements from process/equipment side protection (no load starting, for example) purpose. (iii) Running or tripping of any other system-related drives (to run a standby pump for example). (iv) Drive bearing temperatures not high. (v) Lube oil pressure is adequate. (vi) Manual or automatic/sequential start (if any) command of selected drive.

12.1.1 OLCS for Lubricating Oil Pumps

Start permissive logics from the HT motor side are typically from:

The main drives such as ID fans, FD fans, PA fans, boiler water circulating pumps, BF pumps, etc., if equipped with forced lubricating oil and a control oil system (necessary to bring final control to the minimum necessary for starting a big fan) starting/tripping/shut down logic implementations of the oil pumps are taken care of in the OLCS.

(i) Winding temperatures are within acceptable limits. (ii) Motor bearing temperatures are within acceptable limits. The tripping logics from the drive/process side are typically from:

12.1.1.1 Logics for LOPs Normally the main drives have two LOPs. The starting logic incorporates that the first pump (as selected by the operator) would be started by the operator if LOP suction head/ pressure is available. The LOP would continue to run to develop the lube oil pressure for the main drive. The second pump (as selected by the operator) would cut in automatically if the running LOP trips due to any reason or the LO pressure goes down below the minimum value. It would continue to run as long as the LO pressure goes up over a preset value. The LOPs normally trip due to overload, low suction head/pressure, electrical circuit trouble, etc. It can be shut down manually if required by the operator.

(i) Process pressure/temperature/flow/levels, etc., are beyond acceptable limits. (ii) Some inlet/outlet dampers/valves are to open or close when the starting commands are issued for the main drives and/or any other conditions. If those inlet/outlet dampers/valves fail to execute those commands, then the trip signal is issued to that particular drive after some time delay. (iii) Preferential tripping in case of a disturbed process condition. (iv) Drive bearing temperatures are very high. (v) Lube oil pressure is very low and/or pump running/trip status. (vi) Manual or automatic sequential trip command.

12.1.2 OLCS for Main Drives

Tripping logics of HT drive from process side are typically from:

All the main drive motors, be it HT like 11/6.6 kV or LT like LT AC, related to the boiler part are taken care of in this part of the OLCS. The typical list of drives mainly consists of ID fans (HT), FD fans (HT), PA fans (HT), mill/pulverizer motors (HT), feeder motors (LT), seal air fans (LT), scanner air fans (LT), BF pumps (HT), and boiler water-circulating pump (s), if any (HT). There are in general two sets of interlocks/protection requirements for any drive motor: one from the drive or process side and the other from the motor side. 12.1.2.1

Logics for Drive Motors

The start permissive logics from the drive/process side are typically from: (i) Process pressure/temperature/flow/levels are within acceptable limits.

(i) Winding temperatures are very high. (ii) Motor bearing temperatures are very high.

12.1.3 On/Off Dampers and Valves The on (open) interlock logics are typically from: (i) Process-related interlock signals from high/low/ normal pressure/temperature/flow/levels. (ii) Running or tripping of any other system-related drives. (iii) Main drive on or open command as per the process requirements. (iv) Manual or automatic/sequential on (open) command of selected drive. The stop (close) interlock logics are typically from: (i) Process-related interlock signals from high/low/ normal pressure/temperature/flow/levels.

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(ii) Main drive stop or close command as per the process requirements. (iii) Manual or automatic/sequential off (close) command of selected drive.

12.1.4 Logic Systems for Boiler Tripping, Purging, Starting, Shutdown This part of the logic system is popularly known as the MFT logic part, and it is briefly discussed in Section 12.4 of this chapter. In many thermal power stations, in this particular section, MFT-related logics are developed in a dual redundant mode or even a triple redundant mode. The total inputs, outputs, and processing sections are redundant (dual or triple) to avoid any maloperation of processing units or faulty sensors.

12.2

OLCS in SADC

The SADC philosophy as discussed later in Section 12.5 of this chapter is different for the two major type of boilers. In both types of plants, the SAD are normally operated in a modulating mode through CLCS. In some phases of operation, however, they are subject to maintain some other set point or position as per the command issued by the BMS/FSSS.

12.2.1 Boiler With Fixed Burners and Flue Gas Recirculation Damper The SADC-loop strategy was already discussed in Section 3 instead of Section 12.5 of this chapter. In this case, the OLCS in the BMS issues three distinct output commands requiring the SADC to take care of the same and modulate the dampers accordingly. The following modes of operation are recommended: (i) Furnace safety position mode: BMS issues this command in case of any emergency situation (boiler tripping, for example) as envisaged during boiler operation. At this condition, the air flow is to be maintained at about 25% of the total air flow. (ii) Oil position mode: BMS issues this command when the first set of oil burners is introduced after the purging operation is completed successfully. At this position, the minimum air flow, that is, about 10% the of secondary air flow of the corresponding oil burners only, is maintained so as to ensure an oil flame that may be extinguished in the presence of more air flow. (iii) Pulverized fuel (PF) position mode: BMS issues this command during the introduction of the first set of PF burners. At this point of operation, the air flow of the corresponding PF burner is maintained at about 45% of the secondary air flow.

During normal operation, the main air flow signal from the auto control loop becomes dominant through the maximum selector.

12.2.2 Boiler With Tilting and Corner-Fired Burners and Overfire Air Damper In this type of boiler, the auxiliary air dampers are modulated to maintain the differential pressure (DP) between the wind box (WB) and the furnace. Auxiliary air dampers are located in all two-lettered elevations, for example AA, AB, BC, CD, etc., in between the coal burners. Out of these, in some elevations a provision for oil firing (say, AB, CD, CE, etc.) is made. These dampers become fuel air dampers, maintaining a fixed position during oil firing at that particular elevation. The only OLCS output from the FSSS is issued for adjusting the SADC modulating signal, that is, the case when the MFT trips. The set point for the (DP) between the wind box and the furnace would be typically around 150–200 mm of the water column.

12.3

OLCS in Soot Blower (SB) Control

Apart from the CLCS taking care of the pressure control, the SB control system also comprises the OLCS for selection of the blowers and duration of operation. As discussed in Section 12.6 of this chapter, there are many types of soot blowers and methods of operating them to suit the furnace, type of fuels, type of sensors, etc. In a nutshell, the following operations are possible for operating soot blowers individually or in a selected group as and when required.

12.3.1 Fixed Programmed Time-Based Operation The OLC of the soot blowing system in this strategy is simply through step-by-step operation of the blower in a sequential manner. In the automatic mode of the system, the blowers operate one by one (or in a group) as logically recommended by the boiler manufacturer. They may be modified by the system/plant engineers to suit the site condition as experienced during operation. OLCs take care of the starting time of advancing, the time span of blowing, and the retracting and time gap between the end of one blowing and the starting of the next one of each particular blower (or group).

12.3.2 Temperature-Based Operation The routine operations as discussed above may cause unwanted blowing and result in wear and tear of relatively cleaner tubes with wastage of an expensive soot blowing medium. On the contrary, the heavy soot-deposited tubes may starve the blowing at the right time and frequency.

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This advanced technology enables a cleaning operation of the selected soot blower as per the decision taken by the system logic with the help of sensing the water tube wall temperatures associated with each soot blower. Temperature sensors welded to the tubes sense the actual surface temperature near each soot blower. The measured water tube wall temperature is compared with the corresponding temperature set point based on the saturation temperature of that point. If it become less than the set point, the associated soot blower is given a command to start the blowing operation. This is a need-based operation to clean the portions associated with the soot affected areas only. Though effective for water tubes, this method was not suitable for areas where the fluid flowing through the pipes is a steam or steam-water mixture that has no further bearing on the saturation temperature. For supercritical boilers, where a mixture of water and steam is passed through the tubes above the supercritical pressure of water, there is no way of calculating the desired value to determine the metal temperature, which can be taken as an index of furnace dirtiness.

12.3.3 Heat Transfer/Heat Flux-Based Operation The other strategy of the soot blowing procedure utilizes a more direct method of sensing. The local heat transfer rate is measured by employing a heat flux meter to assess the degree of soot deposition for selectively cleaning the tube walls or air heater ducts. The sensing elements are located in each of the regions of the tube walls surrounding the soot blowers to detect the local heat transfer rate from the hot flue gas to the steam/ water tubes in the furnace or heat exchanging elements (flue gas side) of the air heaters. The heat flux meter output is utilized for operation of the soot blower assembly. Details have been incorporated in Section 12.6.2.3 of this chapter. Other control actions may be attained through the differential temperature.

12.3.4 Leak Test of Oil Lines Leak tests of nozzle valves and trip valves are performed by a separate leak test valve in many plants before plant startup; the logic diagram is shown in Fig. 8.53 for ready reference.

12.4 Burner Management System (BMS/ FSSS) General The very name of the BMS suggests efficient management of the burners and all associated drives and accessories required by the firing system in the furnace. This system has become an indispensable and very important part

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of the steam generation domain, irrespective of the plant size. This management system includes safe starting operation and graceful emergency shutdown of the furnace vis-a-vis the steam generation package as a whole. A similar type of system offered by other major boiler manufacturers is known as the furnace safeguard supervision system (FSSS). Both names in this area are quite familiar and acceptable all over the world. Whatever the brand name of the product, the ultimate purpose of the system along with other normal functions is to act like a watchdog that is supposed to thwart any formation of an explosive fuel/air mixture and avoid implosion in the whole furnace area throughout the complete operating range. The BMS/FSSS is basically a dedicated fire protective system along with logic implemented for start-up, running, and shutdown. It is globally accepted that the guidelines of the National Fire Protection Association (NFPA 8502/8503) of the United States are to be followed as a standard. NFPA defines the BMS as: The control system dedicated to boiler furnace safety and operator assistance in the starting and stopping of fuel preparation and burning equipment and for preventing misoperation of and damage to fuel preparation and burning equipment. BMS/FSSS, as it transpires, is required to perform logical or binary functions with quite a few numbers of inputs simultaneously and issue corresponding binary outputs, paying due attention to the protective aspects, that is, to avoid, well in advance, the firing hazards. There should not be any confusion regarding its role in the boiler operating system. The BMS/FSSS is a completely distinctively separate standalone system and not at all related in any way to the boiler related to normal automatic process controls such as steam pressure/temperature or boiler drum-level controls.

12.4.1 Process-Related Functions Expected From BMS The design basis of BMS/FSSS is aimed to ensure the following jobs: (i) Satisfactory completion of the purge sequence before every starting of fuel firing to ensure that there is no unburnt fuels left over to cause secondary firing. (ii) Satisfactory compliance with each and every start permissive condition for start-up of individual fuel firing equipment. (iii) Flame (both oil as well as PF) monitoring when the fuel-firing equipment is in service. (iv) Sequential operation, including control of drives and monitoring of status feedback, during start up and shut down (cutting in/taking out of elevations, for example).

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FIG. 8.53 Oil leak test—flow and logic diagram.

Boiler Control System Chapter

(v) Initiation of MFT through master fuel relay (MFR) upon adverse firing conditions beyond extreme limits that could be hazardous to both the equipment and personnel so as to stop/lose all sources of fuel, not only at the burner end but also upstream of the same (say, HOTV or mill trip). (vi) Sensing and generating alarm conditions for annunciators or monitors and indicators to the operator’s unit control board (UCB) to facilitate smooth manual operation if necessary. (vii) Provision of all logic and safety interlocks, including tripping instructions compliant with NFPA 8502/ 8503 guidelines. (viii) Inclusion of the first out feature in the system to identify the root cause of any trip, whether related to the burner or the boiler as a whole. (ix) Provision of a complete BMS diagnostic or fault analysis system to immediately identify to the operator any system, subsystem, or module failure. (x) To start/stop/trip burners/igniters on an individual basis in sequence and/or on a corner basis (TT boiler). (xi) Boiler load-based operation of automatic cut in/cut off of burners/elevation. The operator may have the liberty to select the sequence of burner operation, for example, preferential tripping of mills in case of fixed wall burners. (xii) Last but not least, provision of triple modular redundant (TMR) logic and/or a parallel back-up trip path by hardwared MFT or electromagnetic relay independent of processors and I/O modules. With the advent of sophisticated microprocessor-based systems, BMS has long been implemented through the OLCS part of DCS or through programmable logic controllers (PLC) for more reliability, flexibility, and availability, which is discussed in detail in Section 2.2 of Chapter 7.

12.4.2 Hardware- and Software-Related Functions Expected From BMS The following criteria should be available in BMS as a system: (i) The system must be 100% foolproof, based on proven hardware and software. (ii) The system would be provided with an automatic selfmonitoring facility. (iii) All modules must be of a failsafe design so that any single fault in any individual primary sensor, I/O channel, processor, etc., should not jeopardize safety functions. (iv) All faults should be annunciated to the operator immediately with the first out facility. The BMS shall meet all applicable relevant safety requirements,

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including those stipulated in the latest editions of [DIN standard for electrical equipment for furnaces] Verband der Elektrotechnik or VDE 0116, Section 8.7, VDE 0160, NFPA 8502/8503. (v) The BMS hardware may be configured in a tripleredundant, fault-tolerant arrangement as per the modern trend. Three independent sets of hardware (channel) comprising dedicated processors, I/O modules, and communication interfaces would receive the identical input signals. The complete logic part would be implemented independently in each channel. The primary sensors for protection logic should also be triple redundant.

12.4.3 BMS/FSSS Functional Configuration The functional arrangement of the system can better be described in the following segregated areas such as: (i) Logical functions as the heart of the system. (ii) Sensors such as different process and position switches or manual commands. (iii) Different drives, diaphragm/solenoid-operated valves, and actuators. (iv) Operator’s interface or a plaque/keyboard and monitor in the control board. 12.4.3.1 BMS/FSSS Logical and Functional Groups The description of the starting, tripping, shutdown, or other interlocking logic signals is mainly incorporated for FSSS. The basic philosophy is more or less the same although, of course, major differences do exist in some areas where the equipment itself is different. Some of these are indicated below: (i) Firing system: (a) BMS is built around fixed burners with front/ opposed/downshot burners. (b) FSSS is built around tilting burners and a cornerfired system. (ii) Pulverizer system: (a) BMS normally is based on pulverizers of the ballmill type. (b) FSSS is based on bowl- and tube-type mills. (iii) Fuel oil recirculation system: (a) BMS is meant for a long recirculation system only. A short recirculation valve is used for a long shutdown. (b) FSSS takes care of both long and short recirculation systems. There is an orifice across the recirculation valve (normally closed) that provides a constant return flow. (iv) Primary air system: (a) BMS is built around both common PA fans with a header system and individual PA fans. (b) Same for FSSS, depending on the type of mill.

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12.4.3.1.1 Leak Test Valves For some boilers, a leak test facility with valves is supplied for providing a test facility to check the passing through the HOTV and all the downward pipe lines and valves such as nozzle valves of oil burners, including HORV. A leak test valve is installed across the main oil shut off or trip valves (Fig. 8.53). The procedure is described in a simplified way for getting some idea about the system. The following criteria must be fulfilled for starting the test: (i) (ii) (iii) (iv) (v)

The oil pressure before the shut-off valve is adequate. Shut-off valve is fully closed. All nozzle valves of oil burners are fully closed. Leak test valve is fully closed. Oil recirculation valve is closed.

After getting all of the above permissive signals, the test would start when the start command is issued by the operator. It is to be assured that the oil pressure control system is operating satisfactorily so as to maintain the required pressure of the oil header near the shut-off valve. Then the start command by the operator initiates the following activities: (i) Oil recirculation valve is to open. (ii) Leak test valve is to open. (iii) Oil recirculation valve is then to close after 20–30 s if feedback from the above two signals is affirmative. This is done to flush the oil line before the actual testing is performed. (iv) With the oil recirculation valve and oil nozzle valves closed and the leak test valves fully open (oil pressure control already in action), the oil line would be charged gradually through the leak test valve. The DP across the parallel combination of the oil shut-off valve and the leak test valve, which was initially high from the starting point, now shows a decreasing trend. The charging time is set at approximately 60 s so as to ensure complete charging. At the end of the charging time, the upstream and downstream pressures of the leak test valve should be the same with the DP showing very low. On the contrary, if the DP is still high, then the charging failure condition is acted and the leak test could not be carried out further. (v) The leak test would then proceed to the next step with the above DP low permissive confirmation indicating that the oil line is in a fully charged condition. The leak test valve would then close automatically as the next step and the status is maintained for approximately 90 s. At the end of this time, if the DP is still found to be low, meaning no leakage in the downstream part of the oil line having burner nozzle valves and recirculation valve.

(vi) As a next step, the oil recirculation valve would then open automatically as a measure of checking the leakage through the main oil shut-off valve. (vii) The oil recirculation valve is kept open for 60 s to drain all the oil in the pipeline and the DP should show high as the downstream pressure no longer exists. Then the oil recirculation valve is made to close fully. (viii) Then the leak test valve is made fully closed for approximately another 90 s along with the oil recirculation and oil nozzle valves in the full closed position. At the end of those time periods, if the DP is not high, then the main oil shut-off valve appears to be leaking and the leak test failure condition is announced. However, if the DP high condition can persist up to 90 s, the no leakage condition is achieved and the system may be declared as having passed the leak test. 12.4.3.1.2 Furnace Purge Logic Before every start-up of the furnace vis-a-vis the firing system of the boiler, it needs complete purging by blowing air through the furnace for a particular time as recommended by the manufacturer. This may be termed the prefiring purge and is applied strictly to make sure that all the residual unburnt fuels that might have accumulated are entirely eliminated. The air flow rate and the time period may vary, but normally a fairly accurate value may be taken as 30% of the total air for about 5–6 min. Some approximate amount of purged air is suggested to be close to nine times the furnace volume. Purging is not only necessary for the prefiring purge, but is equally important to purge the furnace after every normal shutdown, termed the postfiring purge, to avoid possibility of explosion. Purging is also necessary for the oil burner valves at every time after burner closure, which is normally done by blowing atomizing media for a specified time period (also called scavenging); this is covered in the fuel oil-related logics. During purging, the wind box dampers or air registers maintain a particular position along with other permissive conditions, allowing proper air velocities and travel through different routes consisting of radiant/convection/economizer zones. This complete purging system also enables the checking of proper operational functionalities of air dampers, burner valves, flame monitoring systems, etc., through ensuring permissive signals. The furnace purge cycle normally needs the following conditions to be satisfied for eligible purge start initiation: (i) Loss of AC/DC power for more than 2 s does not exist (to avoid any spurious tripping), meaning AC/ DC power supplies are available [This is mainly done for FSSS with TT burners where equipment in elevation (e.g., nozzle solenoid valves) are

Boiler Control System Chapter

(ii)

(iii)

(iv) (v) (vi) (vii) (viii) (ix) (x) (xi) (xii) (xiii) (xiv) (xv) (xvi) (xvii) (xviii) (xix)

normally run on AC supply whereas DC supplies are used for running equipment for common or unit, for example, HOTV would have a DC solenoid valve (may be double coiled)]. Drum level is not high (It is taken as absence (not) of drum level very high signal, which must exist for >10 s to avoid any spurious tripping). Drum level not low (It is taken as absence (not) of drum level very low signal, which must exist for >10 s to avoid any spurious tripping). Any BFP is on. Any induced draft (ID) Fan is on. Any forced draft (FD) Fan is on. All associated air and flue gas dampers are open. All PAF are off. All seal air fans are off. Air flow is adequate, for example, >30% and <40%. Auxiliary air/SAD are proven modulating at the required position. Windbox to furnace DP is proven satisfied (for TT boiler). Waterwall circulation is adequate. Furnace pressure not high. Furnace pressure not low. All oil valves (trip and individual valves) are in the closed position. All pulverizers are off. All hot air gates are proven closed. The flame scanners indicate no flame.

When all the above start permissive signals are available, the start purge command signal, if issued from the control board, initiates the purging process. It lasts for a specific period of time as set during commissioning (approximately 5 min). Upon expiration of the above counting period, it is taken a successful furnace purge cycle and then the system becomes ready for the next step of operation. 12.4.3.1.3 Fuel Oil Firing Logic When the LDO is used in a plant, it does not require temperature interlock and recirculation of LDO before purging. For HFO, both are necessary for maintaining the proper temperature vis-a-vis the viscosity of the same. So the recirculation-related logics are applicable to the HFO only. However, in some plant designs, the recirculation of LDO is also provided for better mobility and leak test facility. The fuel oil trip valve (FOTV) and the fuel oil recirculation valve (FORV) are required to be opened manually after an MFT condition takes place and prior to the purge cycle being initiated for full-fledged boiler operation. This arrangement fulfills the condition of recirculating the hot oil near the burner area to raise the oil temperature as needed for oil firing. Fuel Oil Recirculation (for HFO Only) Logic

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The sequence of the oil recirculation procedure is as follows: (i) FORV is opened first after MFT and before boiler restart. (ii) FOTV can then be opened with all the following start permissive signals: (a) FORV is fully open. (b) All oil burner valves are fully closed. (c) MFT signal exists. (d) Open PB depressed. After some period of recirculation, if the oil temperature and pressure are found adequate, both the FOTV and FORV valves must be closed to start the purge cycle. Before the purge activities start, leak tests are performed as designed/provided by the manufacturer in some SG plants (discussed in Section 12.4.3.1.1 of this chapter). FORV open logic: The valve can be opened by pressing the push button (PB) from the console if all the oil burner valves are closed. FORV closed logic: The valve closes automatically when any oil burner valves are not closed OR by pressing the close push button. Fuel Oil Trip Valve Logic Fuel oil Trip Valve then can be opened again provided all of the following signals are available: (i) (ii) (iii) (iv)

Purge complete. No MFT. All oil burner valves are closed. FO header temperature (for HFO only) is more than normal (
95°C). (v) FO header pressure is more than normal (15–25 kg/ cm2). (vi) Atomizing steam pressure is adequate, which may be more or less than the FO header pressure, depending on the burner design. (vii) No close/trip command and open PB is depressed. FOTV would trip automatically when any oil burner valve is not closed and if any of the following conditions occur: (i) MFT signal exists. (ii) FO header pressure is very low for more than the specified time. (iii) FO temperature is very low for more than the specified time. (iv) The atomizing steam pressure is low for more than the specified time. (v) Loss of electrical power exists for more than 2 s. Other than the above causes, the FOTV can be stopped manually by selecting the manual mode of operation and then by depressing the stop PB. Fuel Oil Firing (Elevation or Mill Group-Wise) Logic

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Fuel oil firing can now be initiated elevation-wise or mill group-wise as per the burners and firing systems supplied by the manufacturer. The following interlocks are checked for going ahead with fuel oil firing: (i) Fuel oil trip valve is fully open. (ii) Air flow is adequate (typically >30% and <40%). (iii) Burner nozzle tilts are at the horizontal position (for boilers with tilting burner nozzles only) [Items ii and iii above are applicable for first elevation starting only]. (iv) No MFT. (v) Start oil firing command is available manually by the operator or from the automatic sequence logic (if provided). The firing system is different for different manufacturers. As there are two distinct separate systems available worldwide, it is better to discuss separately the firing technique adopted by those two systems. B and W boilers’ firing systems are normally front-fired, opposed-fired, or downshot-fired, having individual igniters and oil guns for every coal burner distributed in two or more elevations/layers depending on the capacity of the power plant vis-a-vis the SG plant. Two such elevations for opposed-fired (may or may not be downshot burner) systems are typical for up to a 250 MW plant, whereas four such elevations for an opposed-fired system are typical for up to a 650 MW plant. In CE boilers, the firing system is based on tangentially corner-fired nozzle burners spread over a number of elevations with in-between air supply compartments called fuel air, auxiliary air, etc. Oil burners are strategically located in some of the elevations in between the coal burners so that one oil burner may support two adjacent (top and bottom) coal burners. In this system, burners operate on a “pair” concept and not on an individual or single-unit basis. A simple logic flow is described to have some idea how it works for TT boilers with FSSS and the same for the wallfired boiler would follow. If the permission for oil firing is available with all safety features taken care of, the following steps are taken manually or sequentially: (a) The oil elevation can be started in the “pairs” or “elevation” firing mode, selected automatically by the status of the PF feeders. The pairs mode is automatically selected when all feeders are off for more than 2 s. The elevation mode is automatically selected when any feeder is proven or an “auto start support ignition signal is established.” Diagonally opposite corners, for example, one and three, are placed in service as one pair. Corner 1 is placed in service initially and after some time, Corner 3 is placed automatically in service. Then, Corners 2 and 4 are placed in service as one pair, similar to Corners 1 and 3.

(b) The following start permissive signals would be checked before proceeding further: (i) No MFT. (ii) The auxiliary air dampers in the associated oil elevation are closed. (iii) Associated oil gun is engaged. (iv) Associated scavenger valve (meant for purging the oil burner that closes after firing) is closed. (v) FO isolation valve is open. (vi) Atomizing steam isolation valve is open. (c) The following events would take place sequentially for an oil burner (corner-wise) to fire: (i) The associated oil igniter [may be HEA igniter/ equivalent] advances to the firing position. (ii) The steam atomizing solenoid operated valve opens. (iii) The oil gun moves to the firing position. (iv) The HFO solenoid-operated burner valve opens. (v) The HEA igniter delivers spark energy to establish the oil flame in that corner. If the flame is established (sensed by the associated oil flame scanner located strategically) after some time and all the commands are complied with, the igniter spark command stops and retracts to the normal position. The concerned oil corner is taken as in service. Other oil corners start in a similar way to make them in service. The oil elevation is taken as in service when a minimum three out of four corners are operating, enabling the next step, that is, proceeding with the starting of the PF firing. Another simple logic flow is also described to have some idea how it works for B and W boilers as follows: All the permissive signals for oil firing must be available with all safety features taken care of and then the following steps are taken manually or sequentially: (a) The firing would be started with LDO first to warm up the boiler to a certain stage such that the HFO firing operation gets sufficient thermal energy to start with. LDO firing arrangements are not provided for all HFO/coal elevations and are normally provided strategically just to warm up before HFO firing could start. For a particular HFO/coal elevation, any HFO burner can be selected manually or in a sequential manner automatically and started. When selected and the start command is available, the burner firing steps are sequentially performed. The following start permissive signals would be checked before proceeding further: (i) No MFT. (ii) HFO header pressure is normal and HOTV is open. (iii) Associated scavenger valve is closed (meant for purging the oil burner that closes after firing). (iv) FORV is open.

Boiler Control System Chapter

(v) Atomizing steam pressure is normal and the isolation valve is open. (vi) Instrument air pressure is normal. (b) The following events would take place sequentially for each oil burner to fire: (i) The oil gun moves to the firing position. (ii) The steam atomizing solenoid valve opens. (iii) The associated oil igniter [may be HEA igniter/ equivalent] advances to the firing position. (iv) The HFO solenoid-operated burner valve opens; simultaneously, the HEA igniter delivers spark energy to establish the oil flame in that corner. The oil igniter then retracts from the firing position to the base position, that is, outside the furnace. If the flame is established (sensed by the corresponding oil flame scanner) after some time and with all the commands complied with such as oil burner valve open, etc., the concerned oil burner is taken as in service or running. A similar procedure is repeated for starting other oil burners and making them in service. When the minimum requisite burners out of the total burners in that elevation are in service, the oil elevation as a whole is taken as in service. This signal would then enable the next step to proceed, that is, the starting of the PF firing. The procedure of LDO firing is similar with a recirculation valve that may or may not be applicable and the atomizing and scavenging media may be air. The igniter may or may not be the same, depending on the situation.

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greater than (for example) 50% and the boiler load is greater than around 30%. Now, any pulverizer can be started after receiving all the start permissive conditions as stated under: (i) Sufficient ignition energy for PF firing is available. (ii) Air flow is adequate, for example, >30% and <40% (this signal is considered redundant after any feeder is proven on for >50 s). (iii) Burner nozzle tilts are in the horizontal position (this signal is not required after any feeder is proven on for >50 s and is applicable to corner-fired boilers only). (iv) No MFT. (v) PA pressure is adequate (after the pulverizer is on, this permissive is no longer required). (vi) All pulverizer discharge valves are open. (vii) Pulverizer outlet temperature is less than the high value (around 95°C). (viii) The cold air gate is open. (ix) The tramp iron hopper (meant for taking out mill rejections) valve is open. (x) The feeder inlet gate is open. (xi) Pulverizer lube oil pressure is adequate for >5 min. (xii) Lube oil sump level is adequate. (xiii) Lube oil temperature is more than sufficient (around 30°C) [after the pulverizer is on, this permissive is not required]. (xiv) No mill trip. (xv) Pulverizer seal air header to the mill under the bowl DP is adequate (about 200 mm wcl). (xvi) Hot air gate is closed. (xvii) All other permissive signals related to this particular type of pulverizer.

12.4.3.1.4 Pulverized Fuel Firing Logic Pulverizer Start Procedure The pulverizers and feeders can now be placed in auto mode of operation and after that, the pulverizers and feeders can be considered for starting after other permissive conditions are satisfied. Before the pulverizers/feeders, the PA fans would be started any time after the furnace is purged successfully. Any start permissive condition signifying the availability of sufficient ignition energy is required for starting PF firing, which is different for every individual pulverizer/feeder set. In general, the following are the required conditions:

When the pulverizer is on, the following interlocked actions would be initiated:

(a) Adjacent fuel oil elevation (upper or lower) in service (for corner-fired burners of CE boilers); if the opposite elevation is in service, that would also provide sufficient ignition energy for B and W boilers. OR (b) Adjacent PF elevation (upper or lower or opposite) is proven with the associated feeder speed running at

After receiving the start command, the pulverizer seal air valve would open first and the seal air header to the pulverizer under the bowl differential pressure would be established. After some time, when a DP of >200 mm (typical value) of wcl is sensed, then the pulverizer hot air gate can be opened and the feeder can be started. During this period, the closing operation would be locked temporarily

(i) Open command to the hot air gate would be issued if the DP between the seal air to the mill and the mill is adequate. (ii) Open CAD to 100% position signal to auto control system would be removed. (iii) The pulverizer temperature control will now receive a release air and temperature control to auto signal. The pulverizer can now be considered as in service and the next step of operation can begin manually or automatically by mode selection.

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for the pulverizer discharge/seal air valve and the associated auxiliary air dampers. The pulverizer trips if any of the following conditions takes place:

(i) Withdrawal of demand signal signifying drive feeder speed to minimum. (ii) All counting timers would be reset, signifying readiness for the next operation.

(i) After expiration of the time period set for establishing the DP across the pulverizer, if the same is not more than adequate (after starting), the pulverizer would be tripped. (ii) The pulverizer seal air header to the pulverizer under the bowl DP is very low (typically around 125 mm wcl) and remains after a specified time. (iii) Pulverizer start command given and not on after a specified time. (iv) Pulverizer on and lube oil pressure is low after a specified time. (v) Loss of ignition energy before it is self-sustaining. (vi) Any of the pulverizer discharge valves is not fully open. (vii) Hot PA duct, pressure very low. (viii) Both FD fans trip. (ix) Both PA fans trip. (x) If both the PA fans and the FD fans are running and any PA or any FD fan trips, then the pulverizers start tripping from the top elevations with some time gap in between tripping until half the pulverizers are available.

After the feeder is on after some time, the following events take place:

(xi) MFT. Other than the above causes, the pulverizers can be stopped manually on manual mode of operation by the stop PB. Feeder Starting and Associated Interlocks (Other Than Tube Mill) The feeder can be placed in service if the following conditions are available: (i) (ii) (iii) (iv) (v)

Pulverizer ignition energy is available. The associated pulverizer remains on. The journal hydraulic pressure is satisfied. No MFT. The pulverizer outlet temperature is more than sufficient (around 55°C). (vi) Feeder speed demand is at a minimum. (vii) Hot air gate is open (the feeder can be placed in service in manual operation without opening the hot air gate). The feeder can now be started and if the feeder discharge chute is not plugged, after some time, the feeder start signal is taken as established and in service if the PF flow signal, that is, the coal on the belt signal, is received. When the feeder running signal is established, the following actions take place, provided the corresponding pulverizer motor power is within limits and the differential pressure across the pulverizer bowl is not high:

(i) The total coal flow totalizing circuit takes this feeder into account after some time. (ii) The feeder speed control is released to auto after expiration of some more time period. (iii) Enables feeder speed to rise >50% and then if sufficient numbers of coal flame scanners sense flame in the corresponding elevation, the combined signals in and logic generate output after expiration of a comparatively long time period of about 3 min signifying a signal pulverizer ignition permissive. The pulverizer ignition permissive confirms that the furnace flame has established and sufficient pulverizer ignition energy is available. At this point, the initial pulverizer start permissive signal to support PF firing is no more required as the flame is self-sustaining. However, it is recommended that a minimum of two pulverizer/feeder sets be established at >50% loading before the ignition support energy is withdrawn. Normally, after the established running of the first pulverizer/feeder set, the adjacent pulverizer/feeder set is brought into service. The pulverizer/feeder set connected to a remote elevation from the running one is brought into service only in an emergency situation. Whatever the situation, standard good operating practice is that the second set be introduced and both feeders are loaded to >50% before ignition energy is removed. Feeder Tripping and Associated Interlocks The feeder is tripped automatically if any of the following conditions takes place: (i) (ii) (iii) (iv) (v)

No coal on belt. The pulverizer motor power is low. Discharge line plugged. MFT. Associated pulverizer is off (may not be applicable for tube mill). (vi) Absence of ignition energy removed within specified time after feeder started.

Other than the above causes, the feeders can be stopped manually by selecting the manual mode of operation and then by depressing the stop PB. Removing of feeders from service requires just the reverse procedure. The pulverizer ignition energy would again need to be reinstated when only two feeders are in service and operating at <50% loading. The fuel oil firing in the corresponding elevation is to be continued until the last pulverizer/feeder set is withdrawn.

Boiler Control System Chapter

For the manual shutdown of the feeder, that is, if the feeder goes off after it was on, the following sequential action would take place after expiration of some prejudged time period: (i) HADs would be closed first if the hot air gate is not already closed for minimizing the chance of a pulverizer fire. (ii) CADs to open 100%. (iii) Pulverizer temperature control’s air (flow?) and temperature control are transferred to manual. (iv) Hot air gate is closed after some time. (v) When the hot air gate is closed, the close command to the HADs is removed if he pulverizer outlet temperature remains <95°C. Seal Air System and Operation of Fans Description

12.4.3.1.5 Master Fuel Trip Signals and Short Description The BMS checks the health of the steam generation package as a whole and senses a boiler emergency trip signal or the MFT vis-a-vis closure of all fuel inputs immediately as well as on the occurrence of any of the following signals: (i) Loss of all FD fans, all ID fans, all BFPs, scanner cooling air, all flames, all fuels, and airflow. (ii) Very low deaerator level, drum level, and furnace pressure. (iii) Insufficient water wall circulation. (iv) Very high furnace pressure, drum level, and MS pressure (for supercritical boilers). (v) Reheater protection operated. (vi) Power supply failure to BMS/FSSS cabinets. (vii) Emergency push button operated. Short Description on Master Fuel Trip Signals While the above signals are self-explanatory, short descriptions of insufficient water wall circulation. and reheater protection operated need some elaboration. (i) Insufficient water wall circulation This type of tripping signal is applicable mainly for forced circulation water systems of the boiler having a separate boiler circulating water pump (BCWP). As the heat transfer design is not based on natural circulation, any sort of insufficient water circulation through the water wall would jeopardize heat transfer and cause the water wall itself to burn out due to loss of cooling media. (ii) Reheater protection operated This tripping signal is included to protect the reheater in situations when the boiler is working but there is no or low flow through the reheater. The conditions may be any of the following:

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(a) Turbine trips/generator circuit breaker (GCB) opens while the HP/LP bypass remains closed for more than a specified time. (b) Load shedding relay operates (heavy load throw off) with the turbine in working condition and with the HP/LP bypass closed for more than a specified time. (c) HP or LP bypass system suddenly trips or closes while working during the house load operation, that is, the turbine and HP/LP BP systems are operating in parallel. (d) HP or LP bypass system suddenly trips or closes while working during the start-up time, that is, when the turbine is bypassed and the boiler steam flow was channeled through the HP/LP BP systems.

12.4.3.2 Sensors Used in BMS/FSSS Functional Configuration Different sensors are used in the BMS/FSSS as dictated by the system, such as different process switches, position switches, flame scanners, and associated electrical contacts or manual commands. Flame sensors are conditioned in a separate standalone cabinet called a scanner cabinet. Sensors and scanners are of various types, namely ultraviolet, infrared, or even visible light. Because flame radiation has a wider range in visible light, nowadays, visible light scanners are more popular. Analog low signals sent by the sensors are not capable of generating binary contacts or analog signals for display. Therefore, they are transmitted to the BMS/FSSS cabinet via the scanner cabinet, where they are processed, conditioned, and converted to generate a binary signal. These detectors are capable of automatic/manual checking of the optical path and have self-diagnostic features. These are available in flameproof and NEMA 4 enclosures suitable for boiler applications.

12.4.3.3 Different Drives: Diaphragm/SolenoidOperated Valves and Actuators Several drives and actuators are connected to the BMS/ FSSS for executing the commands as processed by the system. The drives include high-voltage (HV) unidirectional motors for FD fans, ID fans, PA fans, pulverizers, etc. Bidirectional drives include motorized valves. Some actuators may be solenoid-operated valves, pneumatic diaphragm, or hydraulic piston-operated valves (Solenoid valves are normally double coiled for maintaining a stayput condition in case of wire snapping).

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12.4.3.4 Operator’s Interface or the Plaque/ Keyboard, Monitor in the Control Board This particular item is a combination of different facilities through which the operator can reach the remote drives or devices in case manual intervention is required. All the binary/analog process signals and actuator statuses are made available to the operator so as to enable him to make prompt and appropriate decisions in time of need. The following facilities are normally available in the operator’s interface: (i) Indicators This may be the analog type such as flame scanners or binary, for example, normal/abnormal process conditions through pressure/temperature/level/etc. switches, flame status in on/off form, actuator or bidirectional drives running/stopped/tripped open or close position, condition of unidirectional drives, etc. (ii) Command devices These command devices may be push buttons, selector switches, control switches, etc., required for manual operation or intervention as needed. Normally, separate plaques/consoles are provided for hardware interfaces; a CRT monitor-based system with touchscreen facility or a separate keyboard are also quite common in modern plants.

12.4.4 BMS/FSSS: Manual Operation/ Automation BMS/FSSS was provided normally for achieving the basic safety interlocking features without intervening with the process control system. Through evolution, it also includes the start-up and normal operation/graceful shutdown of the SG plant. With the help of this system, the operator, through regular interaction and observation on the device status, may issue commands from the remotely located plaques/ consoles or a special window in the monitor required for start-up and normal shut down of various devices and/or drives individually or in groups. The system is completely user-friendly and guides the operator to take proper action through the desired sequence. The sequence would not be allowed to proceed further until the requisite permissive signals are available and the proper mode of operation is selected. Once the start-up is done successfully, the boiler is ready for the loading/unloading process and protected by the BMS/FSSS from any hazardous situation. This type of operation is described as manual and the operator is required to take action at every step. A more sophisticated and higher level of operation has also been envisioned, which is popularly called automatic. This type of system allows the operator to issue a single command that enables a group of devices/drives (subloop organized as per process requirement) to start-up or shut down in an appropriate sequential manner. Typically for

boiler operations, complete automation is not required as per the load demand and pulverizer characteristics, which are brought into service one by one to suit the load requirement. Hence, the most straightforward way to divide the total devices/drives is to make it a pulverizer groupwise, which includes the igniter, the pulverizer, the feeder, etc., with manual intervention if needed. For example, the sequence of a particular pulverizer subloop operation may be: (i) To arrange the ignition permissive signal. (ii) If the ignition permissive is available, then the pulverizer motor to start. (iii) Hot air gate to open. (iv) Pulverizer outlet temperature control to be released in auto. (v) Feeder to start. (vi) Feeder speed control to be released in auto. (vii) Windbox dampers or air register control to be released in auto.

12.4.5 Flame Monitoring System As indicated earlier, the flame monitoring system is entirely a separate and standalone system used for monitoring each individual burner flame condition. For tangentially corner-fired boilers, once the burners of a particular elevation are operated at > 30% of their capacity, there is produced a rotating fireball. The ignition energy thus produced in one elevation can support the initial ignition energy required for a fresh introduction of fuel in another elevation. Effectively,the furnace is then considered a single burner and the flame detection is done on a statistical basis by multiple sensors. For a particular elevation, a single flame detector failing to indicate the flame of its adjacent burner is ignored and not shut off due to loss of flame condition. As indicated earlier, the statistical basis is applied by counting all the four corners’ flame or no flame status and then determining the health of that elevation firing condition. F or example, if three of four flame detectors sense no flame, then only that elevation is considered as unsuitable for continuing further firing operation and is taken out of service. In tangentially corner-fired boilers, the change in firing characteristics from start-up to fireball is gradually made by way of increasing the elevation fuel admission to about 30% loading capacity is based on hand on experience providing sufficient factor of safety. For other types of firing systems such as front/opposite/ downshot-fired boilers, the flame produced at all fuel firing rates demonstrates the individual burner characteristics, the same as exhibited by the tangentially corner-fired boilers at low firing rates up to 30% of individual capacity. This means that the type of flame produced does not have that energy capable of providing enough ignition permissive to burners at other locations. In these boilers, each PF burner

Boiler Control System Chapter

requires a separate and individual ignition energy (from nearby oil burner firing). Therefore, the logic development should take care of that aspect for these boilers. BMS in many plants includes interlocks of auxiliaries such as ID/ FD fans and associated dampers as well.

12.4.6 Seal Air Fan Control Redundant seal air fans are provided to supply sealing air to pulverizers and the associated dampers and valves. SA fan suction is normally taken from the PA cold air duct and a differential pressure is available for sealing coal-laden dust from the pulverizers. Any SAF can be started manually or automatically if selected and any PA fan run. The other SA fan would be on standby mode. The concerned discharge damper then receives a command to open. The standby fan would start automatically if the main fan does not start within a few seconds or if the DP is less than about 100 mm. The seal air fans are removed from service automatically when both PA fans are off for more than the specified time. When the seal air fan is off, the associated seal air fan discharge damper is closed.

12.4.7 Scanner Air Fan Control Redundant scanner air fans are provided to supply cooling air to the scanner. ScA fan suction is normally taken from the FD fan discharge and a DP is maintained. Any ScAF can be started manually or automatically if selected and the DP over the furnace is less than about 150 mm wcl; the concerned discharge damper then receives a command to open. The other ScAF would be OFF and on standby mode when its discharge damper receives a closing signal. Standby fans would start automatically if the main fan does not start within a few seconds or if the differential pressure over the furnace is less than about 150 mm wcl. When both FD fans are off, the scanner air emergency damper opens and the cooling air is then supplied with atmospheric air. When any FD fan is ON, the scanner air emergency damper would be closed. Either scanner air fan can be removed from service manually if the scanner duct to furnace DP is >150 mm wcl. In case of loss of unit critical power for more than 2 s, both scanner air fans start and their outlet dampers open simultaneously. If the scanner duct to furnace DP remains <150 mm wcl for >10 s,it is taken as loss of scanner cooling air for boiler tripping.

12.5 Secondary Air Damper Control General To accomplish the efficient burning of any type of fuel, the air supply plays a very vital role. The total air flow must take care of the stoichiometric ratio of the fuel being burnt and the optimum excess air vis-a-vis oxygen percentage,

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etc. The total air flow is normally provided to the furnace in the form of primary and secondary air flows. The low NOx design is accomplished through a separate section of total air flow, which may be termed overfire air. There are specific purposes for the segregation of total air flow. For example, primary air contributes not only to the initial combustion air, but also for transporting the pulverized fuel. The contribution of secondary air flow is to provide additional air or oxygen to make sure of complete combustion of any unburnt hydrocarbon. The purpose of providing overfire air as already discussed above and in Section 10.6 of this chapter is the final part of combustion process to take place purposely delayed to minimize the generation of thermal NOx level. By suitable design, normally the SAD are so adjusted that at the full open position, there is created an optimum swirl position that maintains the long flame and reduces the flame temperature. For wall-fired boilers, secondary air (fuel air and tertiary air) combined together enters the individual burner. The proportioning of the fuel and tertiary air is done within the burner and also needs to be equal in all burners, but may change slightly due to plant conditions. This control strategy is depicted in Fig. 8.4.

12.5.1 Objective: Secondary Air Damper Control The secondary air constitutes two parts: fuel air and tertiary/ auxiliary air. Fuel air allows the higher hydrocarbon or char to burn, and the tertiary/auxiliary air is intended for ensuring the delayed combustion process purposely through a special design to reduce the NOx level. The control strategies depend on the type of boiler as per the manufacturers own designs.

12.5.2 Discussion The basic purpose of this system is to distribute secondary air according to the firing of various burners so as to ensure complete firing of fuel with minimum pollution. 12.5.2.1 Secondary Air Damper Control for WallFired Boiler (With Flue Gas Recirculation System) For wall-fired boilers, secondary air (fuel air and tertiary air) combined together enters the individual burner and the proportioning of fuel air and tertiary air is done within the burner. The control strategy depicted in Fig. 8.4. The secondary air flow control system by the SAD was described in Section 3.3.2.2 of this chapter for a boiler with a flue gas recirculation system. As there are only two major parts of the total air flow, that is, primary and secondary air, their share of flow normally varies from 30% to 35% for the primary air and 65%–70% for the secondary air. Individual secondary air flow is measured for each burner. This measured flow is utilized in the automatic

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(A)

(B)

FIG. 8.54 Secondary air damper control (SADC) for TT boiler.

control loop as well as for the adjustment of equal secondary air flow for all the burners. 12.5.2.2 Secondary Air Damper Control for Tangentially Corner-Fired Boilers The secondary air flow control system by the SAD for tangentially corner-fired boilers is somewhat different. This system is applicable for combustion in the tangentially fired furnace and the auxiliary air part of the secondary air flow is accomplished by the separate auxiliary air dampers, mainly for regulating the velocity and distribution of the air flow at the intermediate stage of combustion. For this type of system, the individual secondary air flow is not measured like the former type of furnace. Here, the fuel air flow (provided for each coal nozzle), being a part of the total secondary air flow, is controlled by the load demand of the boiler through the individual demand of air flow generated from each pulverizer loading through feeder

speed. As the concept of a fireball is just a swirling mass of huge flame produced by the burning of pulverized fuel (PF) and the sufficient air flow to support the combustion, the fuel air dampers act as FCEs and are placed in every fuel injection compartment to supply initial combustion air. The fuel nozzle discharge angle determines the size and rotational velocity of the fireball. Into this swirling mass of flame, the fuel air, a portion of the total secondary air, is injected with the quantity just required for stoichiometric conditions to enable the continuation of the combustion process with delayed mixing. The remainder of the secondary air, that is, the auxiliary air, is directed with the velocity to form a layer of such air between the fireball and the inside walls of the furnace. This layer acts as a cushion over the fireball while rotating in the same direction. It also functions to resist the impingement of slag on the tubes with which the walls of the furnace are lined, and by this, soot blowing becomes easier. While

Boiler Control System Chapter

doing this, the SADC control utilizes the wind box to furnace DP as the measured/process variable. This is maintained at a constant value at the initial stage, and after that, a variable set point up to a certain boiler load and ultimately a higher fixed value. This control is achieved through auxiliary air dampers placed below and over each fuel injection compartment with an aim to provide equal air flow through each compartment they are provided. The DP between the WB to the furnace is maintained at desired preset values by regulating the auxiliary air dampers in all double-lettered elevations. In some of them, oil nozzles are provided and those dampers would be kept at a fixed opening only when oil firing is taking place in that elevation. 12.5.2.3

Summery of Secondary Air Control System

To summarize the secondary air flow control system in a tangentially fired boiler with an overfire damper, it may be noted as: (i) All the secondary air is fed through the wind boxes. (ii) The wind box to furnace DP is maintained by a separate set of SAD called auxiliary air dampers. (iii) A part of secondary air termed fuel air is controlled as per the requirement of fuel flow, that is, fuel air flow is proportional to fuel flow in a particular fuel injection compartment, which results in total fuel air flow being proportional to total fuel flow.

12.5.3 Control Loop Description The control loops for the SADC system for boilers with flue gas recirculation systems were already described in Section 3.3.2.2 of this chapter. A control-loop description for the tangentially corner-fired boilers will be discussed. 12.5.3.1 Measurement of Parameters The wind box to furnace DP is measured through suitable transmitters with sufficient redundancy and voting before actually being used in the control loops. 12.5.3.2

The Control Loop Strategy

The control strategy (Fig. 8.54A) for the SADC system is based on a simple, single-element control concept. The selected signal of the wind box to furnace DP becomes the measured/process variable. The set point is normally a fixed value up to 30% of the boiler load. The set point begins to increase on a further increasing load through a function generator up to a certain load, where it then becomes fixed. However, the set point can be changed manually through selection. The controller output is used to regulate all the auxiliary air dampers adjacent to the coal elevation in tandem at a load >30%. At a load <30%, all these dampers modulate to the same signal.

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Some auxiliary air damper elevations incorporate oil nozzles. Those dampers at a particular elevation would be closed during oil firing starting time and at a fixed opening when oil firing is proven on. Auxiliary air dampers not serving any adjacent coal/oil nozzles would be closed at boiler load >30%. As shown in Fig. 8.54B, fuel air dampers are modulated in proportion to feeder speed/coal flow in the corresponding elevation.

12.6

Soot Blowing System

General In steam-generating plants where an ash-bearing fossil fuel, such as coal, lignite, fuel oil, bagasse/refuse, or any other type of oil/byproduct, is burned, there has always been a perennial problem associated with the deposition of soot during the combustion process, and carried by the hot combustion products to the different heating elements in the furnace as well as in the air heaters. Deposition affects different heat transferring surfaces such as water walls, superheaters, reheaters, and economizer steam pipes covering both radiant and convection zones in the furnace chamber as well as the air heaters, which is called cold end deposition. The fly ash carried along with flue gas combines with moisture and other harmful byproducts when it falls below the condensation temperature. Natural gas is comparatively a better fuel so far as this deposition generally called soot is concerned, as it is almost a clean fuel with negligible ash content. Oil has low ash content, which is water washable. The actual problem of soot deposition lies with the PF-fired boilers. The ash content and coal quality varies widely from country to country and even in different regions of a particular country; hence the form of soot also varies accordingly. When the soot is deposited on the surfaces, it acts as an insulating media and encumbers proper heat transfer from the flue gas to the water/steam/air. The type of deposit or soot may be of dry and powdery substances or hard slag, depending on many factors such as temperature, percentage of ash content, percentage of sodium content in ash, etc. The most difficult soot deposits are caused by PF with high ash content, a high percentage of sodium content in ash, and a low ash fusion temperature, which also acts as an important factor; low value of which temperature means possibilities of more ashes would be stuck to the fluid tube outer surfaces and high deposition in turn. As the practical behavior of the soot deposits is like a thermal insulation between the fluid inside all tubes of the furnace and the hot products of combustion, thereby reducing heat transfer, the more soot deposition on the furnace walls, the less effective the heat gained by the operating fluid, resulting in a steady decrement in fluid

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temperature. In other words, it may be said that the heat transfer from the hot flue gas to the fluid is very high and the temperature of the combustion products leaving the furnace is at a relatively low value when the furnace is in a very clean condition, as is normal in the initial stages of installation. However, over the course of time, the heatexchanging surfaces in the furnace become coated with layers of soot deposition, and the heat transfer from the hot flue gas to the fluid inside the tubes is significantly reduced. As a consequence the temperature of the fluid decreases with the hot flue gas leaving the furnace is significantly increased. This phenomenon over a period of operation causes significant changes in the overall heat balance calculation and finally can pose serious problems for the operator in balancing the steam generation. The high flue gas outlet temperature has many associated problems, as already discussed, such as low overall efficiency, high NOx generation, pollution control violations, etc. There may be some other problems such as the severe plugged condition of some sections and adequate flue gas flow may not be available or erosion may result due to high local gas velocity.

12.6.1 Removal of Soot Depositions Periodic removal of soot deposits is a very important task so far as the efficiency of the unit is concerned. Due to the insulating nature of the soot, the overheating of the boiler tubes is very much natural as the temperature control loop would try to raise the temperature of the steam by allowing more energy input in order to maintain the final parameter. To avoid this situation, the soot blowing system has been developed for selectively cleaning soot deposits from all possible areas. Therefore, it has become imperative for steam-generating plants to have a number of soot blowers physically installed at different locations in the walls of the furnace over the height of the combustion chamber, the superheater, reheater, economizer, etc. This is to intermittently but regularly clean the furnace and heatexchanging walls in the steam and water tube surfaces carrying different types of fluid. Each soot blower, when selected manually or automatically, carries the spray assembly through advance and retract mechanisms and arranges to clean a region of the tube walls around it by blowing a fluid jet at a very high velocity. For soot blowers, the operating blowing media may be anything such as steam, water, or compressed air through the spray nozzle head, which is made to pass through the furnace wall opening into the furnace chamber to eject the cleaning medium under pressure to hit directly against the surface area affected by the soot deposit. As already said, the operation of this type of advance and retract action is done only intermittently as and when necessary. Due to high velocity impingement and the thermal shock by the

comparatively low temperature medium, the blowing medium causes blowing away of loose deposits and high impact loading on the hard and slag deposits. This action causes the same to fall from the tube surfaces, returning a relatively clean tube surface again being exposed for heat exchanging to a higher rate improving things as desired.

12.6.2 Method of Removal of Soot Depositions The location of soot deposition on the different surfaces such as the superheater, reheater, economizer, etc., are not uniform. Even the deposition on furnace walls is not uniform over the height or width of the furnace walls. Depending on the flue gas flow rate/velocity and the travel path, some portion of the furnace experiences more deposition compared to other portions. Prediction of such high deposition zones is very complicated for a particular time period of operation. This is because the exact soot deposition profile may vary on the type of fuel and firing system, in addition to what has already been described. 12.6.2.1

Fixed Programmed Time-Based Operation

It has therefore become the normal practice to adopt the OLC strategy of the soot blowing system through step and sequential operation of the blowers in the well-defined time frame. Quick details are indicated in Section 12.3.1 of this chapter. 12.6.2.2

Temperature-Based Operation

This control strategy discussion above is based on certain presumptions and may not be entirely flawless. It may cause additional wear and tear and wastage of the soot blowing medium, whereas the tubes really needing soot blowing at the right time may not get the service in time. Therefore some advanced method was sought to avoid such an unnecessary situation as per the experience and practical problems. A system strategy was evolved that enables cleaning the selected soot blower as per the decision taken by the system logic. A short discussion is incorporated in Section 12.3.1 of this chapter. Thermocouples welded to the tubes sense the actual surface temperature in the vicinity of each soot blower. The temperature set point is calculated from the saturation temperature of the water flowing through the water tubes as the representative of a soot-laden furnace condition at the particular. The online water tube wall temperatures, if less than the calculated set value, initiate the blowing operation of the associated soot blower. All the soot blowers thus take the need-based command for operation to clean the portions that are associated with the soot affected areas only, without disturbing the cleaner portion blowers as a routine job. This method for obvious reasons is not effective for pipes having a steam or steam-water mixture, which has no further bearing on saturation temperature. At the same

Boiler Control System Chapter

time, it is evident that the local fluid saturation temperature for the water line varies with elevation. It is therefore not a very easy task to determine an actual saturation temperature for obtaining the calculated preset temperature as an index of the degree of soot deposition in the furnace. For supercritical boilers, where a mixture of water and steam is passed through the tubes above the supercritical pressure of water, there is no way of calculating the metal temperature that can be taken as an index of furnace dirtiness. As already told, the metal temperature will vary significantly over the height of the water wall dependent on the local heat distribution and on the water-steam phase state of the mixture flowing through the tubes at that location, which is also next to impossible to determine. Another method employs the measurement of the differential temperature of the metal tube and hot flue gas to initiate soot blowing at a higher value of differential temperature. 12.6.2.3 Heat Transfer/Heat Flux-Based Operation There is another method of determining the strategy of soot blowing, which utilizes the more direct sensing system for selectively cleaning the tube walls of the furnace. The local heat transfer rate is measured by employing a heat flux meter (Fig. 8.55) to assess the degree of soot deposition and not by inferential measurement by the local wall temperature. The sensing elements are located in each of the regions of the tube walls surrounding the soot blowers to detect the local heat transfer rate from the hot flue gas to the steam/ water tubes in the furnace or heat-exchanging elements (flue gas side) of the air heaters. The heat flux meter output signifying the local heat transfer rate is then compared with a manipulated set point that represents the corresponding lower (worst) heat transfer

FIG. 8.55 Schematic diagram of heat flux meter.

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rate value vis-a-vis the maximum acceptable soot deposition a tube wall is covered with. The comparator generates an output whenever the sensed local heat transfer rate is less than the lower allowable set point. A logic processing unit utilizes the comparator output for automatic activation of the corresponding soot blower. As an alternative action, manual intervention is taken from the operator’s place through an alarm/indication provided by the processing unit about this polluted tube/element condition. On the other hand, another comparator may be provided for comparing the heat flux meter output to a manipulated upper heat transfer rate set point representing an acceptable clean condition of the tube walls for generating an output whenever the heat flux meter output is greater than the upper manual set value. When this comparator output is available, the alarm signal would be withdrawn and a healthy indication may take the place of a dirty tube condition. The corresponding soot blower also may be retracted manually or automatically by the logic function. Nowadays, with PC-based systems utilizing software, the heat flux is computed and soot blowing is optimized. As stated earlier, excess soot blowing causes steam wastage, higher boiler maintenance, aggravated tube corrosion, less boiler efficiency, and higher stack opacity, which may not be permissible. The software with a dynamic model is available for the ideal heat transfer rate and cleanliness factor. The heat transfer rate, based on real-time parameters (temperature at various stages), is compared with the ideal value (modelbased) to calculate the cleanliness factor. The other influencing factors included are fuel type, fuel flow, wind box-furnace DP, air parameters (flow, temperature, pressure), etc. The model is improvised in an interactive method with these factors to actually calculate the deviations. Then, soot blowing is optimized in one of the two modes:

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(1) Steam saving mode to avoid excessive soot blowing, assuming that there is a limit of soot blowing frequency beyond which there will not be much improvement in reality. (2) Opacity mode, when in all sections uniform blowing is initiated to reduce opacity. All these are nowadays done by utilizing artificial intelligence and neural networking (“Intelligent Soot Blower Scheduling for Improved Boiler Operation,” by Xu Cheng, R.W. Kephart, and J.J. William). 12.6.2.3.1 Heat Flux Meter: Principle of Operation (Fig. 8.55) As already mentioned, the detector of the local heat transfer rate is basically a heat flux meter mounted directly to the outer side (the combustion chamber side of the furnace) of the tube walls. The transducer is attached to the heat transfer surface by a clamp, ceramic cement, or by any suitable bonding material. The transducer consists of a thermoelectrically dissimilar metal body (than that of the main fluid tubes) and has thermal and electrical connections with the tube metal. Electrical connections are taken from the outer and inner face of the metal body to the processing unit situated outside at a room or ambient temperature environment. The principle of operation of this heat flux meter is that there is created a small temperature difference (due to the thermal resistance of that metal body), which in turn generates an induced voltage or electromotive force (emf) across the transducer metal body whenever there is a flow of heat to or from a surface on which the transducer is placed. The thermoelectric transducer generated signal is on the order of microvolts, but the measuring unit is self-powered without requiring any external excitation voltage. The thermal resistance introduced intentionally by the transducer for the purpose of producing a temperature difference vis-a-vis a potential difference across itself may easily be considered as negligible for all practical purposes. The DC microvolt signal generated by the transducer is then treated and conditioned in a proper way to get analog (4–20 mA) and contact outputs for further application. The final output is proportional to the heat flux. 12.6.2.4

Type of Soot Blowers

12.6.2.4.1 Soot Blowers for Furnace Walls Generally, retractable blowers with short and single nozzles, popularly called wall blowers, are utilized to remove the soot deposition from the combustion chamber area. During forward movement, the blower goes inside the furnace wall by around 50 mm. The blower tip consists of a single nozzle with a high energy jet capable of spraying blowing media at supersonic speed. After the forward movement is completed, the blowing starts with a time lag. The blowing is also accompanied by rotation of the tip by 360° to clean

the deposition up to 1500 mm of the radius. A very difficult type of soot deposition in the form of slag requires denser spacing as the effective cleaning radius becomes around 1000 mm. The frequency of operation depends on the build-up rate of soot deposition. 12.6.2.4.2 Soot Blowers for Radiation/Convection Area The radiation and convection area of the furnace includes heat-exchanging sections such as different superheaters/reheaters/economizers, etc. which are quite away from the furnace wall. The natural selection dictates long retractable blowers going inside the gaps of the tubes for a better approach to the tubes. It is considered the most effective way to clear out the soot deposition from the respective tube surfaces. Generally, the available blowers of this type provide a pair of nozzles located diametrically opposite to each other. While in action, the blower moves forward, accompanied by a rotating motion as well. These two simultaneous motions make the blowing medium of a high-speed, high-energy jet form a resultant spray with a helical pattern for cleaning both the tube surfaces and the spaces in between the adjacent tube assemblies. Some manufacturers recommend the nozzles be provided at a slight angle opposite to each other (with respect to the perpendicular axis) to make them more effective. However, the overall effective cleaning radius may vary from 1200 to 3000 mm (approximately) for various reasons such as the flue gas temperature of a particular area selected for cleaning, the inherent ash characteristics of the fuel being used at that time, or the blowing media. So far as the forward and reverse motions of long retractable blowers are concerned, the same may travel up to the mid way of the width of the furnace, thus covering the total furnace width with the help of the opposite end blowers. The supporting arrangement of long blowers must take care of the boiler overall expansion, which entails the front portion to be supported from the wall itself whereas the rear portion is supported by the boiler platform structure. 12.6.2.5

Blowing Media of Soot Blowers

In general, there are three theoretical media available for soot blowing. Out of that, water is normally not thought of in the recommended list mainly due to the thermal shock it may inflict to the main fluid tubes, causing fatigue and reducing tube life in turn. However, its use cannot be ruled out as it has some special uses in the case of soot deposition characterized with the tenacious and difficult nature of slag formation. The other two blowing media—high pressure steam and air—are the natural choices. Both are equally effective for cleaning. The selection normally depends upon the availability and reliability, along with the cost factor.

Boiler Control System Chapter

Though the usage of air as the blowing medium is considered very efficient, its selection necessitates the installation of separate high-capacity compressors and associated pipeworks. Another disadvantage is the loss of the blowing medium in case of compressor failure. If redundant compressors are provided, that will increase the cost further. However, the most disadvantageous factor is the moisture content in compressed air. The selection of steam as the medium necessitates the installation of pressure-reducing valve pipeworks, as steam would only be available no sooner than the steam generation starts. The pressure-reducing station enables getting steam at the valve outlet a dry quality of super heated steam as the pressure goes down with the steam temperature remains as before. The most significant advantage of steam blowing is that the kinetic energy content out of the nozzle jet in dry steam is almost 200% that of compressed air, which makes it a more effective medium for soot blowing. 12.6.2.6 Location and Operation of Soot Blowers As already said, the type of soot deposition depends upon the fuel ash percentage content, the sodium percentage content in the ash, the ash fusion temperature, etc. The installation location and type of blower must also be decided as per the severity of the problem. Normally, the density of the soot blower location is more in the front and rare water walls of the furnace above the firing zone. There are also provided a set or two below the firing zone. For the convection zone, sets of blowers near and/or between the banks of platen SH, reheater, final SH, before the banks of primary SH and the economizer. The sequence and also the frequency of operation are normally suggested by the boiler manufacturer based on which binary sequence control system is loaded, softwarewise. However, the initial operating strategy though follow the loaded sequence, the accepted one may vary to suit the experience with the plant condition. The frequency normally followed is running one complete cycle in each working shift of the plant, which may also depend on ash content, deposition density in different zones, etc. The deposition study would be conducted so that some sets (maybe groups or singles) of blowers require more frequent operation than others. Nowadays, PC-based software is available to optimize such frequency of operation, as discussed earlier. 12.6.2.7 Soot Blowers for Air Heater Scale or fine grain deposits are seen at the cold end of the air heaters when the flue gas temperature falls below the condensation temperature. At this point, the fly ash, moisture, and sulfur oxides (SOx) combine to form the same on the heating surface of the cold end, which resists the heat transfer as an insulator.

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Appropriate soot blowers clear out unwanted soot deposition from the heating surface and ensure that deposits are not subjected to further moisture. Many types of moisture ingress in the downside part of the flue gas path from the economizer or the steam/water tube leakages, water washing shut off valve leakage, or the unprotected FD fan inlets carrying rain water may enter the system. Above all these causes, the main and frequent source of moisture is the leakage of the steam soot blower system. A suitable quality of steam for soot blowing can eliminate that problem. The AH soot blowers are generally installed at the cold end side where the depositions are observed. The gas outlet side is the natural selection spot, so as to avoid the entrance and mixing of fly ashes and driven away into windboxes. They are installed either in the gas outlet ductwork or as an integral part of the air heater. 12.6.2.7.1 Soot Blowers for Air Heater The number of soot blowers provided for air heaters suit different categories. These are, in general: (i) Retractable soot blowers are used for air heaters having large diameters of about 10 meters and above. (ii) Stationary and multinozzle soot blowers are used for small package air heaters. (iii) Soot blowers with nozzles mounted on a swinging arm are used for air heaters as a popular choice. Retractable Soot Blowers for Air Heaters This type of soot blower is the same as used for the radiation and convection area of the furnace, described in Section 12.6.2.4.2 of this chapter. Swinging Soot Blowers for Air Heaters These soot blowers are large and equipped with an electric power-driven source with a single- or double-nozzle arrangement. The nozzle assembly moves slowly over the face of the heat transfer surface. The nozzle arm simultaneously swings in an arc across the face of the heat transfer surface. The blowing cycle takes one pass across the heating face, either from the periphery of the rotor to the central rotor post or in the reverse direction. 12.6.2.7.2 Media of Soot Blowers for Air Heaters There are two widely accepted media available for air heater soot blowing. One of the blowing media is obviously the high-pressure dry superheated steam and the other is high-pressure (around 12 kg/cm2) or compressed air, with both being equally applicable. The selection normally depends upon the availability and reliability along with the cost factor, as discussed in brief in Section 12.6.2.5 of this chapter. For air heater service, saturated steam is applied sporadically instead of the moisture content in that quality of steam. However, as per experience, dry superheated steam

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is found to be the most effective medium of AH soot blowing than either compressed air or saturated steam. The temperature and pressure value of steam are required to be maintained around 70°C superheat and 15 kg/cm2 for an efficient end result. 12.6.2.7.3 Washing Medium for Air Heater Deposits Water as blowing media is not at all recommended for AH soot blowing, mainly due to the thermal shock. However, its use as a washing medium plays an important role. In case of failure of the soot blowing operation to remove tenacious soot formation, it has been experienced that a water washing cycle for the heating surface yields satisfactory results that would otherwise contribute a considerable amount of draft losses across the air heaters. The equipment normally utilized for this application is a standard one having stationary multiple nozzles and a medium velocity jet producer for different types of air heaters. Water washing may be done during plant shut down, with an isolated air heater portion or full plant running condition taking care of guidelines advised. 12.6.2.8 Pressure and Temperature Controls of Soot Blowing Media It is extremely important that the blowing media must be supplied at the blowing nozzles with adequate pressure and temperature for efficient soot blowing. As has become apparent from the above discussion, steam is the most effective medium for soot blowing and maintaining its pressure and temperature at constant values is very important, as far as the dry superheated steam supply is concerned. The control loops details are discussed separately in Section 10.5 of this chapter.

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Boiler Control System Chapter

[29] U.S Patent no 4607961 Aug. 26, 1986: By M/s John R Wynnyckyj, Edward Rhodes. Canada. [30] Product Catalog on Heat Flux Measurements By M/s International Thermal Instrument Company, Inc. [31] Intelligent Sootblower Scheduling for Improved Boiler Operation: X. Cheng, R.W. Kephart, J.J. William: Westing House Process Control Inc. [32] Putting Combustion Optimization to Work: Nancy Spring Sr.32. Editor: Power Engineering, May 2009. [33] B and W NOx Reduction System and Equipment at Moss Landing power station: B. Becker (B and W), D. Tonn (B and W), N. Stephenson (Cormetech United States), K Speer (Moss Landing United States). [34] Reduction of NOx Through Combustion Optimization: J. Cahill: Emerson Process Experts. [35] Ultra Low NOx Integrated System for Coal Fired Power Plants: G.H. Richards, C.Q. Maney, J.L. Marion, R. Lewis, C. Smith: ALSTOM power Inc.

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[36] An Optimized Supercritical Oxygen Fired Pulverized Coal Power Plant for CO2 Capture: A.H. Seltzer, Z. Fann: Foster Wheeler. [37] Nitrogen oxides emission control options for coal fired electric utility boilers: R.K. Srivastav, R.E. Hall, S. Khan, K Culligan of US Environmental Protection Agency and B.W. Lani, US Department of Energy: J. Air Waste Manag. Assoc. 2005 (vol. 55), 1367–1388. [38] Reducing NOx emissions in tangentially fired boiler—a new approach: A. Kokkinos, D. Wasyluk, M. Brower Babcock, and WilCox and J.J. Barna 2000 Duke Power: ASME International Joint Power Generation Conference July 2000. [39] Windbox arrangement: BHEL Role in Cleaner Environment: Power Gen India 2012. [40] Comparison of NOx Emission Reduction With Exclusive SOFA and Combination of SOFA and CCOFA on Tangential -Fired boilers: S.L. Tongmo Xu, S. Hui, H. Tan, Q. Zhou, H. Hu, School of energy and power engineering PR China: Internet Document.