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  • 1. The Babcock & Wilcox Company Chapter 43 Boiler Operations Effective operation of steam generating equipment has always been critical to maintaining system efficiency, reliability and availability. With advances in sensor technology, control software, and steam generator hardware, efficient operation today means balancing equipment performance with safety requirements and emissions mandates. The procedures used to run steam generating equipment vary widely depending upon the type of system, fuel and application. Systems can range from simple and fully automated requiring a minimum of attention, such as small gas-fired package boilers, to the very complex requiring constant operator attention and interaction, such as a large utility plant. There are, however, a set of relatively common fundamental operating guidelines that safeguard personnel and optimize equipment performance and reliability. When combined with equipment-specific procedures, these guidelines promote the best possible operations. The first half of this chapter focuses on general practices applicable to large multi-burner fossil-fuel fired natural circulation and once-through boilers, though these practices are also generally applicable to most other boiler designs. Starting with Operation of Cyclone furnaces, the remaining sections focus on the unique practices for several important special cases. Because of the intimate relationship between equipment design and operation, additional operating guidelines may be found in other chapters of Steam. Selected areas of particular interest are listed in Table 1. General boiler operations Fundamental principles Although boiler design and power production have become sophisticated, basic operating principles still apply. Combustion safety and proper steam/water cooling of boiler pressure parts are essential. Combustion safety and steam/water cooling requirements Before firing a furnace, there must be no lin- gering combustible material inside the unit. Purging, or removal of this material, assures that the furnace is ready for firing. A standard operating rule for multiple burner boilers is to purge the unit at no less than 25% of the maximum continuous rating (MCR) mass air flow for the greater of at least five minutes or five volume changes. Steam 41 / Boiler Operations Once combustion is established, the correct air/fuel ratio must be maintained. Insufficient air flow may permit the formation of combustible gas pockets and provide an explosion potential. Sufficient air flow to match the combustion requirements of the fuel should be maintained and a small amount of excess air should be admitted to cover imperfect mixing and to promote air and fuel distribution. For emissions reduction, many newer firing systems are staged with overfire air (OFA) ports installed in the upper combustion zones of the furnace. The controlled introduction of combustion air does not eliminate the need to provide adequate operating excess air for safety. In addition to these combustion precautions, it is important to verify boiler water levels. Combustion should never be established until adequate cooling water is in the tubes and steam drum for natural circulation boilers and minimum flow rates are established for once-through boilers. General safety considerations Pressure part failure remains a major concern in the boiler industry. The Table 1 Index to Additional Operating Guidelines Found in Steam System or Component Air heaters Ash handling equipment Auxiliary equipment Burners, coal Burners, oil and gas Bypass systems Chemical cleaning Chemical recovery units Cyclone furnaces Fluidized-bed boilers Particulate removal equipment Pulverizers Scrubbers (flue gas desulfurization) Selective catalytic reduction systems Sootblowers Startup systems Stokers Waste-to-energy systems Water chemistry Water treatment Chapter 20 24 25 14 11 19 42 28 15 17 33 13 35 34 24 19 16 29 42 42 43-1
  • 2. The Babcock & Wilcox Company American Society of Mechanical Engineers (ASME), National Board of Boiler and Pressure Vessel Inspectors, and other organizations have issued extensive codes directed at minimizing these failures. The codes are continuously updated to support quality pressure part design. (See Appendix 2.) Combustion products have also received considerable safety attention. Carbon dioxide (CO2), carbon monoxide (CO), sulfur oxides and chlorine compounds must be considered. While CO2 is not poisonous, it reduces oxygen availability in the flue gas. Sulfur oxides can form acids when breathed into the lungs. Chlorine compounds can form hydrochloric acids or carcinogens such as dioxin. Safety of fuel ash must also be considered. While few ashes contain hazardous materials, heavy metals and arsenic can be present in dangerous levels. In addition, residual combustion may continue in ash collected in hoppers. This is especially true when new emissions reduction combustion systems are being installed. Carbon-in-ash characteristics may be altered under the new low nitrogen oxides (NOx) firing configurations. Finally, safeguards apply when performing maintenance and other work on out-of-service boilers. A confined space may have insufficient oxygen for personnel. Good lighting is important for a safe working environment. In addition, ash accumulations in outof-service boiler areas may still be too hot for maintenance activities. Initial commissioning operations Operator requirements Good operation begins before equipment installation is complete. It includes training of the operators as well as preparation of the equipment. Every operator must be trained to understand and fulfill the responsibility assumed for the successful performance of the equipment and for the safety of all personnel involved. To be prepared for all situations that may arise, the operator must have a complete knowledge of all components: their designs, purposes, limitations and relationships to other components. This includes thoroughly inspecting the equipment and studying the drawings and instructions. The ideal time to become familiar with new equipment is during the pre-operational phase when the equipment is being installed. A distributed control system (DCS) integrates the individual process controllers of a steam generation process into a coordinated, interactive system. It enables the operator to manage the process as a complete system, with control over the interrelationship of various subsystems. Modern distributed control systems are extendable to provide operating personnel with advanced simulations of equipment behavior. Simulator training is typically in real-time, ensuring not only a working understanding of the various steam generator systems, but also the reaction time and rate of the equipment. Combined with simulated equipment failures and 43-2 what-if events, the operating personnel can gain valuable experience prior to initial operation. Preliminary operation should not be entrusted to inexperienced personnel who are not familiar with the equipment and the correct operating procedures. Considerable equipment damage and potential safety events can result from improper preparation of equipment or its misuse during preliminary checkout. Operator training takes on special significance during the initial operating period required to prepare the unit for commercial operation. Knowledgeable and experienced operators are valuable during this period when the controls and interlocks are being adjusted, fuel burning equipment is being regulated, operating procedures are being perfected and preliminary tests are being conducted to demonstrate the performance and capabilities of the unit. Preparations for startup A systematic approach is required when a new boiler is being installed or when any boiler has undergone major repairs or alterations. The procedure varies with boiler design; however, certain steps are required for all boilers. The steps may be classified as inspection, cleaning, hydrostatic testing, pre-calibration of instruments and controls, auxiliary equipment preparation, refractory conditioning, chemical cleaning, steam line cleaning (blowing), safety valve testing and settings, and initial operations for adjustments and testing. Inspection An inspection of the boiler and auxiliary equipment serves two purposes: 1) it familiarizes the operator with the equipment, and 2) it verifies the condition of the equipment. The inspection should begin some time during the construction phase and continue until all items are completed. One item frequently overlooked during the inspection is the provision or lack of provision for expansion. The boiler expands as the temperature and pressure are increased, as do steam lines, flues and ducts, sootblower piping and drain piping. Before pressure is raised in the boiler, temporary braces, hangers or ties used during construction must be removed. Cleaning Debris and foreign material that accumulate during shipment, storage, erection or repairs must be removed. Debris on the water side can restrict circulation or plug drain lines. Debris on the gas side can alter gas or air flows. Combustible material on the gas side can ignite and burn at uncontrollable rates and cause considerable damage. Glowing embers can be the source of ignition at times when ignition is not desired. Fuel lines, especially oil and gas lines, should be cleaned to prevent subsequent damage to valves and the plugging of burner parts. Steam cleaning is recommended for all oil and gas lines. Atomizing steam and atomizing air lines should be cleaned. Hydrostatic test After the pressure parts are assembled, but before the refractory and casing are installed, a hydrostatic test at 1.5 times the boiler design pressure is applied to all new boilers and maintained for a sufficient time to detect any leaks. Testing is equally important following pressure part replacements at pressures specified in local code requirements. Steam 41 / Boiler Operations
  • 3. The Babcock & Wilcox Company The hydrostatic test is normally the first time the new boiler is filled with water; therefore, this is the time to begin using high quality water for the prevention of internal fouling and corrosion. (See Chapter 42.) Demineralized water or condensate treated with 10 ppm of ammonia for pH control and 500 ppm of hydrazine for control of oxygen should be used for all nondrainable superheaters and reheaters. A clear filtered water is suitable for components that will be drained immediately after the hydrostatic test. Temperature plays an important part in hydrostatic testing. The metal temperature and therefore the water temperature must be at or above applicable Code restrictions for hydrostatic testing. For example, these restrictions, as stated in the ASME Code, specify that the hydrostatic test temperature will not be below 70F (21C) to take advantage of the inherent toughness of carbon steel materials as related to temperature. The water temperature should be kept low enough so that the pressure parts can be touched and close inspections can be made. It should not be so high that water escaping from small leaks evaporates immediately or flashes to steam. Also, the water temperature should not be more than 100F (56C) above the metal temperature to avoid excessive metal stress transients. Finally, no air should be trapped in the unit during the hydrostatic test. As the unit is being filled, each available vent should be open until water appears. Instrumentation and controls Every natural circulation boiler has at least two indicating instruments: a water/steam pressure gauge and a water level gauge glass. If a superheater is involved, some type of steam temperature indicator is also used. Once-through type boilers have steam pressure gauges, flow meters and temperature indicators. These indicators are important in that the pressure, temperature levels and flows indicated by them must be controlled within design limits. Therefore, the indicators must be correct. Operation should not be attempted until these instruments are calibrated, and the calibrations should include corrections for actual operating conditions. Water-leg correction for the pressure gauge is one example. (See Chapter 40.) Most modern boilers are controlled automatically once they are fully commissioned. However, before these boilers can be started up, the controls must be operated on manual until the automatic controls have been adjusted for site-specific conditions. Automatic control operations should not be attempted until the automatic functions have been calibrated and proven reliable over the load range. Auxiliary equipment The auxiliary equipment must also be prepared for operation. This equipment includes fans to supply air for combustion and to transport fuel, feedwater pumps to supply water, fuel equipment to prepare and burn the fuel, and air heaters to heat the air for combustion. This equipment also includes an economizer to heat the water and cool the flue gas, ash removal equipment, a drain system to drain the boiler when required, a functioning sootblowing system to adequately clean the heat transfer surfaces, and post-combustion environmental control equipment. Steam 41 / Boiler Operations Chemical cleaning Water-side cleanliness is important for all boilers because water-side impurities can lead to boiler tube failures. They can also lead to carryover of solids in the steam, resulting in superheater tube failure or turbine blade damage. The flushing of all loose debris from the feedwater system and boiler, and the use of high quality water for the hydrostatic test, must be supplemented by proper water-side cleaning before startup. To remove accumulations of oil, grease and paint, the natural circulation boiler is given a caustic and phosphate boilout after the feedwater system has been given a phosphate flush. The once-through boiler and its associated pre-boiler equipment are given a similar flushing. This boiling out and/or flushing should be accomplished before operation. After boiling out and flushing are completed, products of corrosion still remain in the feedwater system and boiler in the form of iron oxide and mill scale. It is recommended that acid cleaning for the removal of this mill scale and iron oxide be delayed until operations at fairly high capacities have carried loose scale and oxides from the feedwater system to the boiler. This results in a cleaner boiler for subsequent operations. Chemical cleaning of internal heating surfaces is described in Chapter 42. Steam line blowing Fine mesh strainers are customarily installed in turbine inlet steam lines to protect turbine blades or valves against damage from scale or other solid material that may be carried by the initial flow of steam. In addition, many operators use high velocity steam to clean the superheater and steam lines of any loose scale or foreign material before coupling the steam line to the turbine. The actual procedure used depends on the design of the unit. Temporary piping for flow bypass to the atmosphere is required with all procedures. This piping and any noise reduction silencers must be securely anchored to resist the high nozzle reaction created during the high velocity blowing period. Several methods are used for blowing steam lines, including particularly high pressure air and steam blowing. The recommended method and the one most used is steam blowing because experience has shown that temperature shock and high velocities are the most effective means of removing loose scale. Sufficient shock is obtained with a series of blows where the steam temperature changes during each blow. Lower pressure, high velocity steam blowing techniques are also available, including those with high velocity treated water injection to promote thermal shocking of the mill scale and debris. Designed and managed correctly, these techniques provide safe removal of scale and other solid particles detrimental to turbine components. There are two basic methods of supplying steam for steam line blowing with a natural or forced circulation boiler. The first method is to use steam returning from the flash tank to the superheater on the forced circulation unit or steam flow from the drum on the natural circulation unit. The second method is to use high pressure steam directly from the boiler. The latter method supplies large quantities of steam at higher 43-3
  • 4. The Babcock & Wilcox Company pressures. Temporary valving is required to control the flow rates during the blowing period. Boiler pressure and temperature can be maintained during the blowing period by continuous firing. If firing is discontinued during the blowing period, it must be remembered that any change in boiler pressure changes the saturation temperature throughout the system. To avoid excessive thermal shock, changes in boiler pressure should be limited to those corresponding to 75F (42C) in saturation temperature during the relatively short blowing periods. Safety valves Safety valves are essential to the safe operation of any pressure vessel, allowing adequate relief of excess pressure during abnormal operating conditions. The set point of each safety valve is normally immediately checked and adjusted if necessary after reaching full operating pressure for the first time with steam. Safety valve seats are susceptible to damage from wet steam or grit. This is an essential reason for cleaning the boiler and blowing out the superheater and steam line before testing safety valves. Safety valves on drum-type boilers are normally tested both for set point pressure and for the closing pressures. This generally requires that the boiler pressure be raised until the valve opens and then reduced for the valves to close. The testing of safety valves always requires caution. Safety valve exhaust piping and vent piping should not exert any excessive forces on the safety valve. Gags should always be used as a safety measure while making adjustments to the valves. As an alternate, safety valves can be tested and set with the boiler pressure below the safety valve design pressure by supplementing the boiler pressure with a hydraulic lift, attached to the valve stem, in accordance with the manufacturer’s instructions. This hydraulic assist method reduces the risk of damage to the valve seat from extended steam flow in a conventional test. Startup Operating procedures vary with boiler design. There are, however, certain objectives that should be included in the operating procedures of every boiler. These objectives include: 1. protection of pressure parts against corrosion, overheating and thermal stresses, 2. prevention of furnace explosions, 3. production of steam at the desired temperature, pressure and purity, and 4. compliance with environmental regulations. Filling In filling the boiler for startup, certain precautions should be taken to protect the pressure parts. First, high quality water should be used to minimize water-side corrosion and deposits. Second, the temperature of the water should be regulated to match the temperature of the boiler metal to prevent thermal stresses. High temperature differentials can cause thermal stresses in the pressure parts and, if severe, will adversely affect the life of the pressure parts. High temperature differentials can also distort the pressure parts enough to break studs, lugs and other attachments. Differential temperatures up to 100F (56C) are generally considered acceptable. A third precaution taken during the filling opera- 43-4 tion is the use of vents to displace all air with water. This reduces oxygen corrosion and assures that all boiler tubes are filled with water. A fourth precaution on drum-type boilers is to establish the correct water level before firing begins. The water level rises with temperature. Therefore, only 1 in. (25 mm) of water is typically required in the gauge glass, except with certain special designs that may require a higher starting level in order to fill all circulating tubes exposed to the hot flue gases. Circulation Overheating of boiler tubes is prevented by the flow of fluid through the tubes. Flow is produced in the natural circulation-type boiler by the force of gravity acting on fluids of different densities. Flow starts when the density of the water in the heated tubes is less than that in the downcomers. This flow increases as firing rate is increased. (See Chapter 5.) Some drumtype boilers are designed for forced circulation and depend on a circulating pump to assist this flow. The once-through type boiler depends on the boiler feedwater pump to produce the necessary flow. Whenever a once-through boiler is being fired, a minimum design flow must be maintained through the furnace circuits. With the use of the bypass system, the fluid can bypass the superheater and turbine to maintain this minimum design flow until saturated steam is available for admission to the superheater and until the turbine is using sufficient steam to maintain the design minimum furnace circuit flow. (See Chapter 19.) Purging Considerable attention has been given to the prevention of furnace explosions, especially on units burning fuel in suspension. Most furnace explosions occur during startup and low load periods. Whenever the possibility exists for the accumulation of combustible gases or combustible dust in any part of the unit, no attempt should be made to light the burners until the unit has been thoroughly purged. The National Fire Protection Association Boiler and Combustion Systems Code (NFPA 85:2004) provides the consensus procedures for purging of various boiler and combustion systems. For multi-burner boilers, the purge rate from the forced draft fan through the stack is at least 25% of the full load mass air flow which must be maintained for the greater of five minutes or five volume changes of the boiler enclosure. A maximum of 40% of the full load mass air flow is specified for coal-fired units only, while no upper limit is set for oil- or gas-fired units. Protection of economizer Very little water, if any, is added to the drum-type boiler during the pressure raising period; consequently, there is no feedwater flow through the economizer. Economizers are located in relatively low temperature zones. Nevertheless, some economizers generate steam during the pressure raising period. This steam remains trapped until feedwater is fed through the economizer. It not only makes the control of steam drum water level difficult; it causes water hammer. This difficulty is overcome if feedwater is supplied continuously by venting the economizer of steam or by recirculating boiler water through the economizer. If a recirculating line is available, the valve in this line must remain open until feedwater is being fed continuously through the economizer to the boiler. Steam 41 / Boiler Operations
  • 5. The Babcock & Wilcox Company Protection of primary, secondary and reheat superheater During normal operation, every superheater tube must have steam flow sufficient to prevent overheating. During startup and before there is steam flow through every tube, the combustion gas temperature entering the superheater section must be controlled to limit superheater metal temperatures to 900F (482C) for carbon steel tubes and 950 to 1000F (510 to 538C) for various alloy tubes. While firing rate is used primarily to control gas temperatures, other means are useful, e.g., excess air, gas recirculation and burner selection. Gas temperature entering the superheater during startup is typically measured with retractable thermoprobes that are removed as soon as steam flow is established in every superheater tube. (See Chapter 40.) Other permanent gas temperature monitoring devices are available, but precautions must be taken so that their installed locations, usage and maintenance are adequate for the task of measuring gas temperatures entering the superheater. These devices are required for the first few startups to establish acceptable firing rates. They should always be used on the once-through type boiler. The two prerequisites for steam flow through every superheater tube are: 1) removal of all water from each tube, and 2) a total steam flow equal to or greater than approximately 10% of rated steam flow. Water is removed from drainable superheaters by simply opening the header drains and vents. Nondrainable superheaters are not as simple, because the water must be boiled away. There will be no steam flow through a tube partially filled with water, and those portions of the tube not in contact with water will be subjected to excessive temperatures unless the gas temperature is limited. Thermocouples attached to the outlet legs of nondrainable superheater tubes, where they pass into the unheated vestibule, will read saturation temperature at the existing pressure until a flow of steam is established through the tube. The temperature of these outlet legs rises sharply to significant increases above saturation immediately after flow is established. Superheater tubes adjacent to side walls and division walls are normally the last to boil clear. These should, therefore, have thermocouples. Protection of drums and headers In most installations, the time required to place a boiler in service is limited to the time necessary for raising pressure and protecting the superheater and the reheater against overheating. In some cases, however, the time for both starting up and shutting down may be determined by the time required to limit the thermal stresses in the drums and headers. Protection of drums and headers can pose significant challenges for operators faced with the need to cycle the steam generator on/off for load demand. Various rules, based on thermal stress analysis and supported by operating experience, have been formulated and accepted as general practice. The rules fall into three categories: one for drums and headers with rolled tube joints, a second set for headers with welded tube joints, and a third set for steam drums with welded tube joints. On drums and headers with rolled tube joints, the Steam 41 / Boiler Operations relatively thin tubes contract and expand at a much faster rate than the thicker drum or header walls; therefore, tube seat leaks are likely to occur if heating and cooling rates are not controlled. Heating and cooling rates have, therefore, been established at 100F (56C) change in saturation temperature per hour. Headers with welded tube connections present no problem with tube seat leaks or with header distortion because the tubes are welded to the headers and the headers are normally filled with fluid at a constant temperature. The concern is mainly with temperature differentials through the header wall and the resulting incipient cracking if excessive thermal stresses occur. Steam drums with welded tube connections are not subject to tube seat leaks but, because they contain water in the bottom and steam in the top, the heating and cooling rates vary between the top and the bottom. This results in temperature differences between the top and the bottom. Stress analyses show that the principal criterion for reliable rates of heating and cooling should be based on the relationship between the temperature differential through the drum wall and the temperature differential between the top and bottom of the drum, both of which are measured in the same circumferential plane. Analysis also shows that the allowable temperature differentials are based on tensile strength, drum diameter, wall thickness and pressure. Therefore, each steam drum has its own characteristics. To determine the temperature differentials during the periods of startup and shutdown, it is necessary to continuously and accurately obtain the outside and inside surface temperatures of the drum shell. Temperatures of the outside of the drum shell are best determined by thermocouples. At least six outside thermocouples are required: two on each end, one on the top and bottom (all outside the internal baffle and scrubber area) and two in the center, one top and one bottom. Temperatures of the inside of the drum shell are best determined by placing thermocouples on one of the riser tubes entering the bottom of the drum, one on each end, and one in the center. There are two periods when the steam in the top of the drum is hotter than the water occupying the lower half. One period is soon after firing begins on boilers with large nondrainable superheaters. Steam forms first in the superheater and flows back to the steam drum where it heats the top of the drum. A second period is during cooling when cold air is pumped through the boiler by the forced draft fans. The boiler water cools, but the steam in the top of the steam drum remains at essentially the same temperature. The temperatures of the top and bottom can be brought close together by flooding the steam drum with water. Firing must be stopped and water must not be allowed to spill over into the superheater. A high level gauge glass is needed for this operation. However, thermocouples attached to the superheater supply tubes can be used to indicate when the drum is flooded because there is a sharp change in temperature when water enters these supply tubes. Allowable temperature differentials for cooling are stringent, considerably more so than for heating. Fast cooling 43-5
  • 6. The Babcock & Wilcox Company should, therefore, be supervised with the use of thermocouples and a high level gauge glass. Cooling is particularly important when the boiler is to be drained for short outages. The steam drum must be cooled to permit filling with the available water without exceeding the allowable temperature rate of change. (See Fig. 1.) A wider latitude is permitted if the water used for filling is hotter than the steam drum. Before removing the unit from service, a more uniform cooling can be achieved by reducing pressure to approximately two-thirds of the normal operating pressure. This reduces the temperature of both the water and steam in the steam drum. Rate of Change, F(C)/h Operating techniques for maximum efficiency Fuel is a major cost in boiler operation. It is therefore important to minimize fuel consumption and maximize steam production. Although a boiler’s efficiency is primarily a result of its design, the operator can maintain or significantly improve efficiency by controlling heat losses to the stack and losses to the ash pit. Stack losses The total heat that exits the stack is controlled by the quantity and the temperature of the flue gas. The quantity of gas is dependent on the fuel being burned, but is also influenced by the amount of excess air supplied to the burners. While sufficient air must be provided to complete the combustion process, excessive quantities of air simply carry extra heat out of the stack. The temperature of the flue gas is affected by the cleanliness of the boiler heat transfer surfaces. This in turn is dependent on sootblower and air heater operation. Optimal cleanliness of the heat transfer surfaces is achievable with commercial sensors and control systems that measure the heat transfer effectiveness of the boiler banks, evaluate against the design duty, and clean only on an as-needed basis. While high gas exit temperatures waste energy, excessively low temperatures may also be unacceptable. Corrosion can occur at the acid dew point of the gas where corrosive constituents condense on the cooler metal surfaces. Ash plugging of heat transfer surfaces can be aggravated by the presence of condensate. Equipment protec- 400 (222) Unsafe 300 (167) Safe 200 (111) 0 0 100 200 300 400 500 (56) (111) (167) (222) (278) Total Change of Saturation Temperature, F(C) 600 (333) Fig. 1 Permissible rate of change for saturation temperature, drum and furnace. 43-6 tion and performance of backend environmental components [selective catalytic reduction (SCR) system protection, for example] can also be constraints in desirable steam generator gas temperature. Pressures and temperatures Most boilers supply steam to turbines or processes that require heat. These processes rely on design pressures and temperatures. Deviations from the set points may result in lower overall efficiency of the power cycle, loss of production, or damage to the product or process. In units that produce saturated steam, boiler temperature is directly related to the operating pressure. For many industrial applications, the process requirements dictate the steam temperature and consequently the operating pressure. For electric power producing steam systems, steam temperature has a significant impact on turbine efficiency. Modern controls can typically maintain this temperature within 10F (6C) of the desired setting. Each 50F (28C) reduction in steam temperature reduces cycle efficiency by approximately 1% on a supercritical pressure unit. Variable pressure operation Historically, utility power boilers in the United States (U.S.) have been operated at a constant steam pressure and the turbine load has been controlled by varying the throttle valves at the turbine inlet. This causes an efficiency loss due to the temperature drop across the throttle valves. In variable pressure operation, boiler pressure is varied to meet turbine requirements. This can significantly improve cycle efficiency when operating at low loads (15 to 40% of MCR). However, boiler response to turbine requirements is slower in this mode. When fast response is needed, pressure increments are used. At a given pressure, the throttle valves control the steam to the turbine and provide quick response. As turbine requirements increase and the valves approach full open position, the boiler pressure is increased to the next increment. This arrangement provides high efficiency while retaining quick response. Emissions requirements The majority of the steam generators in operation today were not originally designed for today’s environmental regulations. Hardware changes made to accomplish the emissions reduction are typically accompanied by new operating philosophies and guidelines for efficiency and equipment protection. To maintain optimal SCR efficiency and minimal ammonia usage/slip the combustion system is optimized to generate the lowest level of nitrogen oxides (NOx) possible. Staging of combustion air is frequently used in firing system upgrades. Sufficient care must be taken to ensure that lower furnace corrosion associated with the reducing atmosphere is not excessive, especially with high sulfur content fuels. Depending on system design, there may be tradeoffs between lower NOx generation and increases in the carbon content in the ash and carbon monoxide (CO) in the flue gas. To maintain ash quality suitable for disposal/sale, operational balance must be achieved within the combustion process. Furnace combustion is also usually controlled to achieve any specific CO emissions rate. Combustion optimization A modern DCS is equipped Steam 41 / Boiler Operations
  • 7. The Babcock & Wilcox Company to offer significantly more information and analysis, assisting the operating personnel in optimizing the steam generator. Closed loop neural network systems and other advanced intelligent control systems have made strides in maintaining optimum operations consistently throughout the operating range. Variants of these systems use complex databases and algorithms of unit-specific operating scenarios to guide the controlling parameters during steady state and transient operation. Extensive parametric testing of the unit is conducted to define the characteristics and boundaries of the operating variables. As long as no subsequent mechanical modifications are added and proper equipment maintenance is available, these advanced control systems are capable of consistently returning the steam generator to its most optimum operating condition. A significant attribute of these systems is the ability to target specific results during optimization and change the targeted parameter as needed. As the result, NOx can be minimized during selected periods and heat rate can be minimized the rest of the operating year. Key operation functions Burner adjustments The fuel and combustion air combine and release heat at the burners. To maintain even heat distribution across the width of the furnace, air and fuel flows must be evenly supplied to all burners. While individual burner adjustments affect a particular burner, they also impact adjacent burners. Most boilers have multiple burners in parallel flow paths on the front and/or rear furnace walls. Burners must be similar in design and must be adjusted in the same way to optimize air flow distribution. For a detailed discussion of burner features refer to Chapters 11 and 14. Adjustments can typically vary the turbulence and flow rates in burners. Increased turbulence increases the air-fuel mixing. It also increases the combustion intensity, provides faster heat release, reduces unburned carbon (UBC) in the ash, permits operation with less excess air, and increases boiler efficiency. However, increased slagging, increased NOx emissions and higher fan power consumption can also result. Fuel adjustments on an individual burner basis are also possible, either through diverter mechanisms in the fuel preparation system or through flow balancing devices in the coal transport piping. While possible, the dynamic balancing of fuel flows is difficult. As with combustion air adjustments, potential impacts to adjacent burners will require reliable feedback on relative flow rates to be effective as a dynamic operational tool. Advances in flame characterization systems and sensors for post-combustion constituents are providing more precise feedback targets for on-line fuel balancing, as are in situ coal and combustion air flow measurement devices. Overfire air port adjustments Burner systems intended for NOx reduction are typically staged at the primary combustion elevation and usually operated with less than theoretical air for complete combustion. The remaining air needed to complete the burning process is introduced separately, above the highest burner Steam 41 / Boiler Operations zone. The overfire air (OFA) flows are typically varied as a function of load, based on parametric testing performed during commissioning. While normally satisfactory for ensuring complete combustion and emissions compliance, any changes to fuel type, fuel preparation quality, or the fuel/air transport systems will require close monitoring of OFA system performance. More advanced dynamic control schemes are available, dependent on measurement feedback of the combustion process in the upper furnace zones. Excess air The total combustion air flow to a boiler is generally controlled by adjusting forced and induced draft fan dampers in relation to the fuel flow. Excess air is the amount of additional combustion air over that required to theoretically burn a given amount of fuel. The benefits of increasing excess air include increased combustion intensity, reduced carbon loss and/or CO formation, and reduced slagging conditions. Disadvantages include increased fan power consumption, increased heat loss up the stack, increased tube erosion, and possibly increased NOx formation. For most coal ashes, particularly those from eastern U.S. bituminous coals, the solid to liquid phase changes occur at lower temperatures if free oxygen is not present (reducing conditions) around the ash particles. As a result, more slagging occurs in a boiler operating with insufficient excess air where localized reducing conditions can occur. Localized tube metal wastage may also occur in furnace walls under low excess air conditions but the impact is less clearly defined. The absence of free oxygen (a reducing atmosphere) and the presence of sulfur (from the fuel) are known causes of tube metal wastage. The sulfur combines with hydrogen from the fuel to form hydrogen sulfide (H2S). The H2S reacts with the iron in the tube metal and forms iron sulfide, which is subsequently swept away with the flue gas. High chlorine levels can also promote tube wastage. Although coals and most conventional fuels burned in the U.S. contain very little chlorine, it is a problem in refuse-derived fuels. (See Chapter 29.) Fuel conditions Fuel conditions are temperature, pressure and, if solid, mean particle size and distribution. Cooler temperatures, lower pressure and larger particle size contribute to less complete combustion and increased unburned carbon in the ash. Conversely, if the fuel is hotter, finer and at a higher pressure, combustion is improved. Unfortunately NOx emissions and slagging can also increase with these conditions. Current day combustion technologies employ multi-zone low NOx burners to control the pace of combustion and are more demanding on mean particle size and distribution for control of NOx and UBC production. Effects of fuel preparation equipment on boiler performance Fuel preparation equipment readies the fuel for combustion and can have a significant impact on pollutant emissions. The preparation equipment may be the crushers, pulverizers and drying systems on coal-fired units; fuel oil heaters and pumps on oil-fired units; refuse handling, mixing or drying equipment on refuse-fired boilers; or fuel handling, blending, sizing and delivery equipment on stoker-fired units. If this equipment is not properly operated, the fuel may 43-7
  • 8. The Babcock & Wilcox Company not be completely burned, leaving UBC in the ash or carbon monoxide (CO) in the flue gas. The operator must monitor the fuel preparation equipment. Knowledge of the equipment, its maintenance record and operating characteristics is essential. Feedwater and boiler water conditioning requirements The main function of a boiler is to transfer heat from combustion gases through tube walls to heat water and produce steam. Clean metal tubes are good conductors, but impurities in the water can collect on the inside surface of the tubes. These deposits reduce heat transfer, elevate tube temperatures, and can lead to tube failures. Water conditioning is essential to minimize deposits and maintain unit availability. (See Chapter 42.) Sootblower operations As discussed in Chapter 24, a sootblower is an automated device that uses steam, compressed air, or high pressure water to remove ash deposits from tube surfaces. Sootblowing improves heat transfer by reducing fouling and plugging. However, excessive sootblowing can result in increased operating cost, tube erosion and increased sootblower maintenance. Conversely, infrequent sootblower operation can reduce boiler efficiency and capacity. Optimum sootblowing depends on load conditions, combustion quality and fuel. With the increased dependency in the U.S. on Powder River Basin (PRB) coal and the cost attractiveness of spot market fuels, advanced sootblowing control systems are being increasingly deployed to assist the operators. Unlike manual guidelines, these intelligent systems do not rely on fuel characteristics to influence cleaning patterns. Rather, they focus primarily on the heat transfer surfaces and monitor efficiency. Since cleaning decisions are based solely on an as-needed basis, the intelligent sootblowing systems are ideally suited for operations dealing with changing fuel blends. Furnace-based sootblowing equipment is increasingly being controlled with advanced control schemes that monitor the heat flux in select zones, supervise blower operation for effectiveness, and minimize thermal shock to the furnace wall tubes. Personnel safety Operating instructions usually deal primarily with the protection of equipment. Rules and devices for personnel protection are also essential. The items listed here are based on actual operating experience and point out some personnel safety considerations. 1. When viewing flames or furnace conditions, always wear tinted goggles or a tinted shield to protect the eyes from harmful light intensity and flying ash or slag particles. 2. Do not stand directly in front of open ports or doors, especially when they are being opened. Furnace pulsations caused by firing conditions, sootblower operation, or tube failure can blow hot furnace gases out of open doors, even on suctionfired units. Aspirating air is used on inspection doors and ports of pressure-fired units to prevent the escape of hot furnace gases. The aspirating jets can become blocked, or the aspirating air supply can fail. In some cases, the entire observation port or door can be covered with slag, causing the aspirating air to blast slag and ash out into the boiler room. 43-8 3. Do not use open-ended pipes for rodding observation ports or slag on furnace walls. Hot gases can be discharged through the open ended pipe directly onto its handler. The pipe can also become excessively hot. 4. When handling any type of rod or probe in the furnace, especially in coal-fired furnaces, be prepared for falling slag striking the rod or probe. The fulcrum action can inflict severe injuries. 5. Be prepared for slag leaks. Iron oxides in coal can be reduced to molten iron or iron sulfides in a reducing atmosphere in the furnace resulting from combustion with insufficient air. This molten iron can wash away refractory, seals and tubes, and leak out onto equipment or personnel. 6. Never enter a vessel, especially a boiler drum, until all steam and water valves, including drain and blowdown valves, have been closed and locked or tagged. It is possible for steam and hot water to back up through drain and blowdown piping, especially when more than one boiler or vessel is connected to the same drain or blowdown tank. 7. Be prepared for hot water in drums and headers when removing manhole plates and handhole covers. 8. Do not enter a confined space until it has been cooled, purged of combustible and dangerous gases and properly ventilated with precautions taken to keep the entrance open. Station a worker at the entrance and notify the responsible person. 9. Be prepared for falling slag and dust when entering the boiler setting or ash pit. 10. Use low voltage extension cords or cords with ground fault interrupters. Bulbs on extension cords and flashlights should be explosion proof. 11. Never step into flyash. It can be cold on the surface yet remain hot and smoldering underneath for extended periods even after the pressure parts are cool. 12. Never use toxic or volatile fluids in confined spaces. 13. Never open or enter rotating equipment until it has come to a complete stop and its circuit breaker is locked open and any other drive devices are immobilized. Some types of rotating equipment can be set into motion with very little force. These types should be locked with a brake or other suitable device to prevent rotation. 14. Always secure the drive mechanism of dampers, gates and doors before passing through them. 15. Do not inspect for tube leak locations until metal and refractory surfaces are cool, and ash accumulations are removed. Performance tests Many steam generating units are operating day after day with efficiencies at or near design values. Any unit can operate at these efficiencies with the proper instrumentation, a reasonable equipment and instrument maintenance program, and proper operating procedures. Early in the life of the unit when the gas side is relatively clean, the casing is tight, the insulation is new, the fuel burning equipment has been adjusted for optimum performance and the fuel/air ratio has Steam 41 / Boiler Operations
  • 9. The Babcock & Wilcox Company been set correctly, performance tests should be conducted to determine the major controllable heat losses. These losses are the dry gas to the stack and, on coalfired units, combustible in the ash or slag. During these tests, accurate data should be taken to serve as reference points for future operation. Sampling points that give representative indications of gas temperatures, excess air and combustibles in the ash should be established and data from these points recorded. Items related to the major controllable losses should also be recorded at this time, e.g., draft losses, air flows, burner settings, steam flow, steam and feedwater temperatures, fuel flow and air temperatures. Procedures for performance tests are provided in the American Society of Mechanical Engineers (ASME) Performance Test Codes, PTC 4, Steam Generating Units; PTC 4.2, Coal Pulverizers; and PTC 4.3, Air Heaters. Abnormal operation Low water If water level in the drum drops below the minimum required (as determined by the manufacturer), fuel firing should be stopped. Caution should be exercised when adding water to restore the drum level due to the potential of temperature shock from the relatively cooler water coming in contact with hot drum metal. Thermocouples on the top and bottom of the drum will indicate if the bottom of the drum is being rapidly cooled by feedwater addition, which would result in unacceptable top-to-bottom temperature differentials. If water level indicators show there is still some water remaining in the drum, then feedwater may be slowly added using the thermocouples as a guide. If the drum is completely empty, then water may only be added periodically with soak times provided to allow drum temperature to equalize. (See Protection of drums and headers.) Tube failures Operating a boiler with a known tube leak is not recommended. Steam or water escaping from a small leak can cut other tubes by impingement and set up a chain reaction of tube failures. By the loss of water or steam, a tube failure can alter boiler circulation or flow and result in other circuits being overheated. This is one reason why furnace risers on once-through type boilers should be continuously monitored. A tube failure can also cause loss of ignition and a furnace explosion if re-ignition occurs. As discussed later in the chapter, process recovery boilers are particularly sensitive to tube leaks because of the potential for smelt-water reactions, which can lead to boiler explosions. Any unusual increase in furnace riser temperature on the once-through type boiler is an indication of furnace tube leakage. Small leaks can sometimes be detected by the loss of water from the system, the loss of chemicals from a drum-type boiler, or by the noise made by the leak. If a leak is suspected, the boiler should be shut down as soon as normal operating procedures permit. After the leak is then located by hydrostatic testing, it should be repaired. Several items must be considered when a tube failure occurs. In some cases where the steam drum water level can not be maintained, the operator should shut off all fuel flow and completely shut off any output of steam from the boiler. When the fuel has been turned Steam 41 / Boiler Operations off, the furnace should be purged of any combustible gases and feedwater flow to the boiler should be stopped. The air flow should be reduced to a minimum as soon as the furnace purge is completed. This procedure reduces the loss of boiler pressure and the corresponding drop in water temperature within the boiler. The firing rate or the flow of hot gases can not be stopped immediately on some waste heat boilers or on certain types of stoker-fired boilers. Several factors are involved in the decision to continue the flow of feedwater, even though the steam drum water level can not be maintained. In general, as long as the temperature of the combustion gases is hot enough to damage the unit, the feedwater flow should be continued. (See later discussion for chemical recovery units.) The thermal shock resulting from feeding relatively cold feedwater into an empty steam drum should also be considered. (See Protection of drums and headers.) Thermal shock is minimized if the feedwater is hot, the unit has an economizer, and the feedwater mixes with the existing boiler water. After the unit has been cooled, personnel should make a complete inspection for evidence of overheating and for incipient cracks, especially to headers, drums, and welded attachments. (See Personnel safety, especially when the potential of hot materials, boiler fluids, or combustibles is present.) An investigation of the tube failure is very important so that the condition(s) causing the tube failure can be eliminated and future failures prevented. This investigation should include a careful visual inspection of the failed tube. In some cases, a laboratory analysis or consideration of background information leading up to the tube failure is required. This information should include the location of the failure, the length of time the unit has been in operation, load conditions, startup and shutdown conditions, feedwater treatment and internal deposits. Shutdown operations Boiler shutdown is less complicated than startup. The emphasis again is on safety and protection of unit materials. Two shutdown situations may occur: a controlled shutdown, or one required in an emergency. Under controlled conditions, the firing rate is gradually reduced. Once the combustion equipment is brought to its minimum capacity, the fuel is shut off and the boiler is purged with fresh air. If some pressure is to be maintained the fans are shut down and the dampers are closed. The drum pressure gradually lowers as heat is lost from the boiler setting; a minimal amount of air drifts out of the stack. If inspection and maintenance are required, the draft fans remain on to cool the boiler more quickly. If the unit is equipped with a regenerative air heater, it is shut down, allowing the boiler to cool faster. If a tubular air heater is present, this heat trap can only be bypassed to help cool the boiler. The cool down rate should not exceed 100F (56C) per hour of saturation temperature change to prevent damage due to thermal stress. In an emergency shutdown, the fuel is immediately shut off and the boiler is purged of combustible gases. Additional procedures may apply to the fuel feed equip43-9
  • 10. The Babcock & Wilcox Company ment. The boiler may be held at a reduced pressure or may be completely cooled as described above. Operation of Cyclone furnaces The Cyclone component of a Cyclone™ furnace is a cylindrical chamber designed to burn crushed coal. The basic design, sizing and general operation of Cyclone furnaces are covered in Chapter 15. The key feature that affects operations is the collection of most of the coal ash as a liquid slag in the Cyclone chamber. This slag is continuously tapped into the furnace through a hole at the discharge end of the Cyclone. The slag collects on the furnace floor and flows through a tap into a water filled tank where the chilling effect of the water leaves the slag in granular form. Unique operational issues center upon maintaining desired furnace slag tapping without excessive maintenance. Fuels A key operating parameter of Cyclone units is the selection of a proper coal. Fuels acceptable for Cyclone firing must generally meet the following specifications subject to site-specific conditions: Bituminous coals: 1. maximum total moisture – 20% 2. ash content – 6 to 25%, dry basis 3. minimum volatile matter – 15%, dry basis 4. ash (slag) viscosity – refer to Table 2 5. ash iron ratio and sulfur content – See Chapter 15, Fig. 4 Subbituminous coals and lignite: 1a. maximum total moisture for a direct-fired system, but without a pre-dry system – 30% 1b. maximum total moisture with pre-dry system – 42% 2. minimum high heating value – 6000 Btu/lb (13,956 kJ/kg), as-fired 3. ash content – 5 to 25%, dry basis 4. ash (slag) viscosity – refer to Table 2 For proper combustion and efficient unit operation, properly sized crushed coal is required. This is especially important for subbituminous coals, where the higher moisture content requires a finer coal grind to maintain Cyclone temperatures and to minimize unburned carbon in the flyash. Combustion air All Cyclone furnaces use heated air at a high static pressure. The air temperature ranges from 500 to 750F (260 to 399C), depending on the unit design and the rank of the fuel. The static differential across the Cyclone ranges from 32 to 50 in. wg (8 to 12.5 kPa). This high pressure produces the very high velocities which, in turn, produce the scrubbing action required for complete combustion of the crushed coal. A key variable in Cyclone operation is excess air. For bituminous coals, which are generally high in sulfur and iron content, 15 to 18% excess air is recommended at full load operation. Operation at lower excess air can promote an oxygen-deficient reducing atmosphere, which can significantly increase unit 43-10 maintenance. Operation with molten slag and deficient air can result in iron sulfide attack (wastage) of the boiler tubes. When operated with insufficient excess air, fuels with high iron content can smelt the iron from the ash. A pig iron, which forms a strong bond to the boiler tubing, can form and may result in tube damage during deposit removal. Operation with high levels of excess air leads to lower thermal efficiency and results in Cyclone cooling. This hinders slag tapping. On multiple Cyclone units, it is important to accurately measure the secondary air and coal flow to each Cyclone to ensure it is operating with the proper air/fuel ratio. Because proper excess air is essential, theoretical air curves should be used to readjust the excess air levels when one unit of a multiple Cyclone furnace is removed from service. Firing subbituminous coals is generally more difficult due to increased fuel moisture which must be evaporated during combustion. Units designed for subbituminous coal firing have provisions for higher air temperature and generally run with 10 to 12% excess air. Due to environmental concerns, some bituminous coal-fired Cyclone furnaces have been converted to burn low sulfur subbituminous coal or coal blends. Subbituminous coal has a lower ash content than most bituminous coals. As a result, less slag is available to trap the raw coal particles. This, combined with the depressed flame temperature caused by the increased moisture content, can result in less coal being entrapped in the slag where the combustion is completed. Acting on the additional environmental concerns, utilities have installed OFA systems for combustion NOx control. While furnace wall corrosion remains a concern, worthwhile NOx reductions have been attained with fuel rich stoichiometry and lower sulfur fuels. These Cyclone operating techniques have changed the operating practices of these slagging combustors. When firing higher moisture subbituminous coal, smaller crushed coal particle size is required and higher transport air temperature is desired. Table 2 Ash Viscosity Requirements Maximum T250* Coal Rank Ash Viscosity As-Fired Total Moisture % Bituminous 2450F (1343C) Subbituminous − direct-fired 2300F (1260C) Subbituminous/lignite** 2300F (1260C) Lignite*** 2300F (1260C) 0 to 20 21 to 30 31 to 35 36 to 42 * T250 is the temperature at which the ash viscosity is 250 poise. ** For lignite firing, a fuel pre-dry system is required. *** For high moisture lignite firing, pre-dry and moisture separator systems are required. Steam 41 / Boiler Operations
  • 11. The Babcock & Wilcox Company As the moisture content reaches the 20% range at design Cyclone fuel inputs, clinkering and UBC in the Cyclone and on the furnace floor can increase dramatically. Levels of unburned carbon also increase in the ash in the economizer, air heater and precipitator hoppers. Supplemental firing with fuel oil or natural gas along with design changes may be required if the unit was not originally designed for this condition. Several Cyclone units are operating on high moisture North Dakota lignite fuel. This is accomplished by the use of a pre-dry system, as illustrated in Chapter 15. In this system, hot air [750F (399C)] is introduced to the raw coal stream prior to crushing in a pressurized and heated conditioner. The hot air-coal mixture then travels to a cyclone separator, where the saturated air and some coal fines are separated from the coal stream and are injected into the lower furnace. The dried coal is then carried by a lift line to the Cyclone burner. Operation of once-through boilers Principles In full once-through operation, high pressure water enters the economizer and high pressure steam leaves the superheater; there is no recirculation of steam or water within the unit. The path is through multiple parallel tube circuits arranged in series. Design and construction details are found in Chapters 19 and 26. This type of boiler can be conceptualized as a long heated pipe with continuous coolant flowing through it. As the fluid progresses through the components, heat is absorbed from the combustion process. The final steam temperature is dependent on the feedwater inlet temperature and ratio of the fluid flow to the heat available, which have important implications on unit operation. Operating practice The once-through steam generator, referred to by The Babcock & Wilcox Company (B&W) as the Universal Pressure (UP) boiler, has operating characteristics not seen in drum units. The UP boiler is capable of operating above the critical pressure point [3200 psi (22.1 MPa)] and can deliver steam pressure and temperature conditions without a steam-water separation device after startup. The original UP boilers are typically designed and operated for base load operation. To address the increasing demand for operational flexibility, the B&W Spiral Wound Universal Pressure (SWUP) boiler is capable of variable pressure operation and on/off cycling, as well as load cycling and base load operation. This spiral wound tube geometry UP boiler, including its startup and bypass systems, minimize the thermal upsets during transients, allowing rapid load changes. To start up a UP boiler, a steam/water separation device (flash tank or vertical steam separator), with appropriate valving and piping to bypass and return fluid to the cycle, is supplied. The modern bypass systems are highly automated and very effective in achieving smooth operation. The bypass system is in service only during low load operation. Steam 41 / Boiler Operations The major control functions for fuel, air, water and steam flow are highly interactive placing unique constraints on operation. Though today’s integrated control systems manage many operating functions, it is still important for the operator to fully understand the relationships between short-term (transient) and longterm (steady-state) energy transfer effects and to carefully monitor and coordinate, as required, all control actions. Modern control systems are often referred to as coordinated systems. (See Chapter 41.) The combustion systems are conventional; they are subject to the normal concerns of fuel utilization, efficiency and safety. The operator has three main controls for operating a UP boiler: 1. firing rate, 2. feedwater control, and 3. steam flow/steam pressure. Firing rate The long-term demand for firing rate is directly proportional to load. The short-term effects of firing rate impact steam temperature and pressure. During increases in firing rate the steam temperature increases until the feedwater flow is increased to compensate and balance the new firing rate. Steam pressure increases in a similar fashion to that of a drum boiler. In a supercritical pressure application, there is no large rise in specific volume during the transition from liquid to vapor conditions. However, there is still a large increase in specific volume as a supercritical fluid is heated. With this expansion, the turbine control valves are opened and flow is increased to maintain pressure. With the many interactions that are a consequence of firing rate, the operator and automated control system should strive to position firing rate for the desired electrical load and then manipulate other variables to control temperature and pressure. Feedwater flow The outlet steam temperature is dependent in steady-state conditions on the ratio of feedwater flow rate to firing rate. Because it is desirable to position firing rate based on electrical demand, feedwater flow control is based on outlet steam temperature. The short term effect of feedwater flow changes is to increase or decrease steam pressure and electrical load. The load change results because energy is placed into or brought out of storage through cooling or heating of the boiler metals. However, this load change is transitory. Pressure is a measure of the balance between steam flow and feedwater flow. The outlet pressure is constant if they are matched. The operator can, therefore, use feedwater to assist in recovery from transients and upsets, but ultimately must position feedwater flow for the appropriate outlet steam temperature. Steam flow/steam pressure In steady-state conditions, steam flow is the same as feedwater flow, and boiler pressure is determined by turbine throttle valve position. In the short term, a change in steam flow impacts steam temperature and electrical load. This is because increasing steam flow at a constant firing rate affects the balance of the two and the steam temperature drops initially as a consequence to electrical load increase. This can not be a lasting effect, however, as steam and feedwater flows eventually match 43-11
  • 12. The Babcock & Wilcox Company each other at a different pressure. Similarly, load may be changed by adjusting the turbine throttle valve which increases or decreases steam flow, but this load change comes from depleting or building stored energy in the form of pressure. As above, steam flow may be manipulated to help restore control of steam temperature and load, but it ultimately must be controlled to achieve the desired operating pressure. Operating skills Efficiency The supercritical boiler provides very high cycle efficiency. This inherent efficiency can be maintained throughout boiler life with proper instrumentation and maintenance. The operator must be thoroughly trained to know the optimum operating parameters. Deviations in these parameters may then be addressed with instrument maintenance, direct operator action (such as sootblowing) or an engineering investigation. Performance tests should be conducted on a regular basis. Besides the conventional need to minimize heat losses, these tests can be used to confirm control system calibration. Test results should be reviewed with the operator. Startup systems Chapter 19 provides a comprehensive overview of the configuration and operation of state-of-the-art startup and bypass systems for variable and constant furnace pressure once-through boiler systems. Systems for UP boilers have evolved as the understanding and experience of the oncethrough concept have increased. A key requirement for the startup system is to maintain adequate flow in the furnace walls (30% for most variable pressure supercritical units, 25% for most constant pressure supercritical units, and 33% for most subcritical units) to protect them from overheating during startup and low load operation. Initial designs (first generation) simply bypassed any excess flow from the furnace, not required for the turbine power generation, directly to the condenser from the high pressure turbine inlet. Second generation startup systems added a steamwater separation device called a flash tank (including steam-water separation equipment) after the convection pass enclosure circuits, but upstream of the primary superheater. This permitted the generation of dry steam for turbine roll and synchronization. The flash tank was effectively a small drum including drum internals. (See Fig. 2.) Subsequent constant pressure third generation designs moved the bypass line plus necessary valves (200 and 201) downstream of the primary superheater so that the primary superheater is always in the initial flow circuit. (See Fig. 3 for key elements.) Steam is produced in the flash tank because the pressure reducing valve (207 in Fig. 3) drops the pressure from supercritical to approximately 1000 psig (6.89 MPa) in current designs. For a smooth transition or changeover from startup (flash tank) to oncethrough operation, the enthalpy of the flash tank steam must be matched with the enthalpy leaving the 201 valve. Because the flash tank generally operates at 1000 psig (6.89 MPa), the throttle pressure to the turbine is only ramped to full pressure after transition from the flash tank. 43-12 Due to the need for flexibility of the variable furnace pressure SWUP designs, startup and bypass systems have changed to incorporate features of the subcritical drum and supercritical once-through startup systems. As shown in Fig. 4 (key elements only), the SWUP system has evolved from the second generation system shown in Fig. 2 with the replacement of the valves and flask tank with vertical steam separators, a water collection tank and a boiler circulation pump. At startup and low load, the flow passes through the vertical steam separators where steam is removed and sent to the superheater and water is discharged to the water collection tank. Water then flows through the boiler circulation pump to maintain the minimum furnace wall circulation. Any excess water accumulated during startup is sent to the condenser through the 341 valves. When unit operation reaches the load where the sum of the furnace flow plus the attemperator spray flows is equal to the main steam flow rate, once-through operation is achieved, the 381 valves are closed, and the boiler circulation pump is shut down. Limits and precautions The once-through nature of UP boilers results in special limits and precautions that must be observed for reliable and dependable operation: 1. Feedwater conductivity – unlike a drum boiler which can release suspended solids through blowdown, all hardness and other contaminants that enter the boiler in the feedwater are deposited on the water side of the heating surface or in the superheater. Deposition can lead to overheating and tube failures. Boiler firing must be stopped if conductivity exceeds 2.0 microsiemens for five minutes or if it exceeds 5.0 microsiemens for two minutes. The operator should be trained in water quality control requirements. (See Chapter 42.) 2. Minimum feedwater flow – firing is not permitted unless the boiler feedwater flow is above the specified minimum. The boiler is to be immediately shut down if flow falls below 85% of minimum for twenty seconds or 70% of minimum for one second. Fig. 2 Second generation UP startup system schematic. Steam 41 / Boiler Operations
  • 13. The Babcock & Wilcox Company Fig. 3 Third generation UP startup system with primary superheater in initial flow circuit. 3. Feedwater temperature – the heat input required per unit of water flow is dependent on the difference between the feedwater inlet temperature and the controlled outlet steam temperature. If feedwater temperature is reduced while the outlet temperature is maintained (by overfiring), the heat input to the furnace can exceed design levels that may result in damage to the tube material. For units that were not designed for a feedwater heater out of service, removal of a feedwater heater will require that the final steam temperature be reduced to hold furnace heat input rates within design limits. Unless specific information is provided, the general rule is to reduce steam temperature one degree F for every two degrees F that the feedwater temperature is low. TTV Spray Water Attemperator Secondary Superheater HP Reheater Primary Superheater Convection Pass Vertical Steam Separator(s) L P 341 Furnace Economizer 381 Water Collection Tank Boiler Circulation Pump Fig. 4 Startup system for a SWUP boiler (key elements). Steam 41 / Boiler Operations IP Condenser 4. Overfiring – for supercritical units, the fluid in the furnace has no latent heat of vaporization as in a subcritical boiler. Consequently, as heat is absorbed, the fluid temperature is always increasing and the furnace tube metal temperatures increase. Firing in excess of design rates can result in excessive tube metal temperatures in selected furnace locations. The operator must therefore observe a strict limit of transient heat input. A maximum of 1.15 times the steady-state rate is a typical guideline. This rate, at various load conditions, should be clearly established by combustion tests. 5. Tube leaks – operation with a tube leak is not recommended on any boiler. For once-through units, the situation is more critical because the leakage can reduce cooling flow to subsequent tubes or circuits downstream. 6. Low pressure limit – a constant pressure supercritical UP boiler must be tripped if the fluid pressure in the furnace falls below 3200 psig (22.1 MPa) for fifteen seconds. Failure to do so can result in improper circuit flow, inadequate tube cooling and furnace tube failures. For the SWUP boilers the units are designed for specific variable pressure ramps. To avoid possible tube damage, the units must operate along design pressure ramp curves. Operation of fluidized-bed boilers Chapter 17 provides a detailed discussion of fluidized-bed combustion systems. The following sections provide selected remarks on general fluidized-bed boiler operation, both circulating fluidized-bed (CFB) systems and bubbling fluidized-bed (BFB) systems. CFB systems overview The CFB is constructed and behaves like a conventional drum boiler in many respects. However, thermal performance, combustion efficiency, furnace absorption pattern and sulfur dioxide (SO2) control are strongly influenced by the mass of solids in the bed (inventory), the size distribution of the bed material (bed sizing), and the circulating rate of the bed (flow rate). Bed density can be described as bulk density which is a measure of the material weight per unit volume. There is a higher density and inventory in the lower furnace, made of coarser particles (average size 200 to 400 micron), and a lower density and inventory in the upper furnace (also called furnace shaft) made of finer particles (average size 100 to 200 micron). Fig. 5 shows the density of the bed with respect to furnace height and indicates the effect of load. To integrate these influences into operating procedures, the CFB is equipped with additional instrumentation which provides operator input for bed management. These inputs are as follows: 1. Primary zone ∆P – The gas-side differential pressure is measured across the primary furnace zone [from the air distribution grid to an intermediate elevation of about 6 ft (1.8 m) above the grid] and is an indication of the coarser bed inventory. This variable is managed as a function of boiler load and desired furnace shaft ∆P, utilizing the bed drain flow for control. 43-13
  • 14. The Babcock & Wilcox Company 2. Shaft ∆P – The furnace shaft ∆P, from the intermediate elevation to the furnace roof, indicates the shaft bed density and is managed to follow boiler load with corrections for primary zone temperature control. It is influenced by the multi-cyclone dust collector (MDC) recycle rate, the primary to secondary air split, and excess air setting. 3. Lower bed (or primary zone) temperature – The lower bed temperature is set by the operator as a primary control variable for optimal combustion and emission performance. The shaft ∆P, primary to secondary air split, and excess air controls are used to control this operating parameter. The variables mentioned above are typically not available on conventional boilers. However, the overall operation is similar. Fuel feed is set by steam requirements (pressure), total air flow is adjusted to follow fuel flow, and excess air is set to optimize combustion and unit efficiency. Shaft bed density is then predominantly used to control the lower bed temperature, the most important variable on a CFB boiler. The lower bed temperature is usually controlled to a fueldependent set temperature [for example 1550F (843C) for lignite and 1620F (882C) for petroleum coke] which results in optimal combustion efficiency and SO2 absorption. The optimum bed operating temperature from combustion and emission standpoints is from 1500 to 1650F (816 to 899C), depending on fuel. Another variable that is controlled somewhat differently in a CFB is the air admission to the furnace. The total air flow is divided into primary and secondary flows. Because total air flow is based on fuel flow, the primary to secondary air split becomes another important parameter affecting emissions and bed temperature. The split affects the lower bed density, shaft density, and control of the primary zone temperature. The optimum air split is determined as a function of steam flow during commissioning tests. Once the optimum primary to secondary air split (as a function of steam flow) has been determined for automated control, the operator should not need to independently manipulate the split. Solids management is also unique to CFBs. Once the bed material inventory has been established, bed inventory is maintained by the fuel ash and sorbentderived solids flows in most cases. Any change in inventory necessary to accommodate load change comes from the MDC hoppers. In the case of firing low-ash and low-sulfur fuels, solids input with fuel ash and sorbent may not be adequate to provide enough bed material for furnace temperature control. This also may be the case when firing waste fuels requiring a high bed drain rate for removing oversized material, e.g., rocks. If a shortage of solids for maintaining bed inventory occurs, the first source to add bed material would be recycling a usable part (properly sized material) from the lower furnace bed drain. If this is not sufficient, inert bed material fed from an external source, e.g., sand, would be provided. With the sometimes complex relationships where changes in one variable impact several temperatures and flows, control logics are provided to automatically control these inter-relating parameters with minimal, 43-14 if any, operator actions needed. However, the operator must be trained to understand these relationships and to control upsets to establish and maintain stability if necessary. Fuel sizing and fuel characteristics Coal firing Fuel sizing is very important to successful boiler operation. It impacts the furnace heat release profile: fine particles tend to burn higher in the furnace shaft while coarse ones burn predominantly in the primary zone. For medium and high ash fuels, fuel sizing also impacts sizing of bed particles and, correspondingly, bottom ash to flyash split. When fuel variation occurs, the operator should be thoroughly trained on the required adjustments in case the variations are outside the range of the programmed control logics. Biomass firing Biomass fuels provide a particular challenge in CFB operations because of continuous variations in size, shape, moisture content, and heating characteristics. To minimize operating problems, fuel sources should be continuously blended to achieve as uniform a consistency as possible. Modest inventories are needed – large enough to permit blending for uniformity of feed but not large enough to result in excessive inventory storage times. Bed material sizing should be checked on a regular basis to ensure that the bed material is not deteriorating. Care must be taken in such sampling procedures because of the high bed material temperature. Startup and shutdown considerations Chapter 17 provides general guidelines for the startup of CFBs. Hot and cold startup conditions are distinguished by the temperature of the furnace solids inventory, either higher or lower than the auto-ignition temperature of the main fuel established at the end of the boiler purge sequence. As with any boiler, prior to startup and after shutdown the unit must be purged according to the latest applicable NFPA codes. An important part of a cold startup is the warming of the bed material with auxiliary fuel overbed burners designed for this purpose. During normal operation, a Fig. 5 Typical bed density profile for a circulating fluidized bed. Steam 41 / Boiler Operations
  • 15. The Babcock & Wilcox Company CFB is loaded with enough bed material to provide a 20 in. wg (50 kPa) pressure differential across the primary zone. During the warming process, bed materials are introduced to raise the bed pressure drop from 5 in. wg (1.25 kPa). Auxiliary fuel is used to increase and stabilize the primary zone temperature at about 1000F/538C (varies somewhat depending on main fuel) in preparation for main fuel introduction. Simultaneously, the boiler metal temperatures as indicated by steam pressure (saturation temperature) must be within the heatup rate allowed for the boiler pressure parts. Upon ignition of the auxiliary fuel, the flue gas temperature entering the U-beams and the steam-cooled surfaces must be monitored and maintained below 950F (510C) until 10% of the MCR steam flow is established through the steam-cooled circuits. Once the primary zone temperature is stabilized at the fuel auto-ignition point, the main fuel is introduced and the bed temperature can be gradually raised to about 1500F (816C) where the auxiliary burner may be shut off. Boiler load can be increased from this low load operation with circulating mode being established with increasing solids, fuel and air flow. The rate of increase must be controlled such that the bed temperature remains stable. Primary air to total air ratio is further adjusted to improve combustion and reduce emissions. Overbed burners are used to assist with the burnup of unburned carbon particles in the primary zone of the furnace. If the boiler is being shut down for maintenance and personnel entry into the boiler setting is required, all solids must be completely removed from the boiler and hoppers, and the boiler temperature must be below 120F (49C) prior to entry. (See personnel safety discussed earlier.) BFB systems Overview As is the case with its CFB counterpart, bed management of a BFB is important. Bed inventory, bed sizing, makeup and drainage must be integrated into operating procedures from data collected during commissioning tests. The BFB is also equipped with additional instrumentation to assist the operator in developing the unit-specific operating guidelines. 1. Primary zone ∆P – the gas-side differential pressure is used as an indication of bed height. The primary zone may be compartmented on the air side for coal firing, and multiple ∆P cells are then displayed. 2. Bed temperature – the typical bed temperature range is 1350 to 1650F (732 to 899C) and is a primary control variable. Because control of this variable is critical, multiple thermocouples are installed in the bed. The operation of a BFB is similar to that of other combustion technologies in that fuel and air demands are set by the required steaming conditions. Bed temperature is controlled within the desired range by the primary/overfire air split for biomass firing and by selected compartment slumping for coal firing (see Chapter 17). If an SO2 sorbent is used, it is usually metered in proportion to the fuel flow. Various interactions can Steam 41 / Boiler Operations occur when manipulating control variables and the operator must be specifically trained to respond to upsets. These responses include: 1. Fuel flow control – fuel feed is increased or decreased based on steaming requirement. Changes in fuel feed have a short-term impact on bed temperature. 2. Bed height – height is controlled by adding material from the makeup system or by removing material through the drain system. 3. Air control – total air is primarily controlled based on steam flow. Air may be biased by the operator to change bed conditions. Increasing primary or bed air at a given load increases bed turbulence and burnout in the bed, while the secondary air changes opposite to the bed air change to control constant total air at a given load. Reducing bed air at a given load would have the opposite effect. The operator must, therefore, bias the set point based on combustion conditions. Fuel sizing variations, moisture content, and higher heating value are most likely to influence combustion conditions. 4. Bed material flow – material flow to the primary zone is through makeup and bed drains. Because these are generally intermittent devices, the operator must observe control variable trends, particularly height, and make appropriate adjustments. Coal sizing Careful attention to coal sizing (minimum and maximum) is critical to successful unit operation for both under-bed and over-bed feed systems. Finer particles are elutriated too quickly and coarser particles tend to take too long to burn completely. In either case, UBC and SO2 emissions (if being controlled) both increase. An optimum size range exists for each fluidized-bed system and fuel type. The proper size range is fine tuned through unit operating practice. In addition, for the over-bed feed system fuel size interacts with spreader speed, angle of injection and gas velocity. Operation of Kraft recovery boilers Overview The Kraft recovery boiler has three purposes in today’s pulp and paper industry: 1. recovery of sodium and sulfur compounds from the spent pulping liquor in forms suitable for regeneration, 2. efficient heat recovery from burning the liquor to generate steam for process use, and 3. operation in an environmentally responsible manner, cooling the combustion gases to allow back end particulate collection and minimizing the discharge of objectionable gases. Steam flows can exceed 1,000,000 lb/h (126 kg/s) at superheater outlet pressures as high as 1500 psi (10.34 MPa) and final steam temperatures of up to 950F (510C). These units burn black liquor with solids contents up to 75 to 80% and with heating values decreased to about 5500 to 5600 Btu/lb (12,793 to 13,026 kJ/kg). A detailed review of designs and general op- 43-15
  • 16. The Babcock & Wilcox Company erating practice is provided in Chapter 28. Selected operating issues are highlighted below: 1. 2. 3. 4. black liquor combustion process and air flow, auxiliary burners, operating problems, and smelt-water reactions. Black liquor combustion process and air flow Unlike the firing of conventional fossil fuels, recovery boiler combustion goes through several distinct stages. Black liquor firing is composed of drying, volatile burning, char burning and smelt coalescence as discussed in Chapter 28. This has a distinct impact on unit operation and air addition. All modern B&W recovery boilers are equipped with three levels of combustion air. These are known as the primary, secondary and tertiary air streams in order of increasing elevation in the furnace. A fourth level, called quaternary, can be added for additional NOx and particulate control (see Chapter 28). Primary air Primary air is in the lowest zone in a recovery boiler furnace. The air ports are located approximately 3 ft (0.9 m) above the furnace floor. Admitted on all four walls of the unit, the primary air provides perimeter air around the bed at low velocity and low penetration, so the boiler does not lose combustion. The primary air is critical to bed stability, bed temperature and reduction efficiency. Secondary air High pressure secondary air penetrates the full cross-section of the unit and is admitted at the top of the bed providing the combustion air for ignition and the heat to dry black liquor droplets and support pyrolysis. This air also helps control SO2, total reduced sulfur (TRS) and CO emissions. Finally, secondary air controls the shape of the top of the bed. Fig. 6 indicates the proper bed shape with the relative locations of the air ports and liquor nozzles. Tertiary air Tertiary air is admitted at the upper elevation, above the liquor guns. Like secondary air, it is admitted at high pressure to provide penetration across the width of the furnace to complete the combustion process. This is an oxidizing environment to control CO and TRS emissions. To maintain combustion in the proper location, the air flow splits and pressures must be properly maintained. Ranges of typical air flow distributions, inlet temperatures and pressure differentials are summarized in Table 3 for the two dominant firing systems, stationary and oscillating. Successful stationary or oscillating firing depends on the correct liquor droplet size. This size must permit complete in-flight drying before reaching the furnace wall or bed. The variables in black liquor combustion include liquor percent solids, temperature and pressure at the spray nozzles, spray nozzle sizing and splash plate angle, and number and position of black liquor guns in service. Other variables include the vertical and angular movement of the oscillators or the off-horizontal angle of the liquor guns for stationary firing. Other factors on the air side include total excess air; air temperature(s); air splits between the primary, secondary and tertiary ports; and the static air pressure in each of these air zones. 43-16 Fig. 6 Proper bed shape for a black liquor recovery boiler – three air level design. The objective in the manipulation of all of these variables is to control the steps of the drying and combustion of the liquor, and control bed temperatures. The result is stability of operation, with minimum plugging and emissions. A comprehensive discussion of recovery boiler emissions is provided in Chapter 28. Auxiliary burners Recovery boilers are equipped with oil- and/or natural gas-fired auxiliary burners located at the secondary and tertiary air port elevations. The burners in the secondary windboxes are used for unit startup, as black liquor can only be fired into a heated furnace with an auxiliary ignition source. The secondary burners are also used to stabilize the smelt bed during an upset condition and to burn the bed out of the unit on shutdown. Operating problems Two problems unique to recovery boiler operations are plugging and aggressive tube corrosion. Plugging of the superheater, boiler bank or economizer is generally caused by two mechanisms. The first is condensation of the fume or normal gases given off by the black liquor combustion. The hot combustion gases that leave the lower furnace contain vaporized compounds that condense when the gas temperature is cooled in the upper zones of the boiler, superheater or boiler bank. This condensation is dependent on gas temperature. The material condenses on the cooled heat transfer surfaces such as furnace screen tubes or primary superheater tubes. It also precipitates out when the gas temperature falls below approximately 1100F (593C). In either case, this material is a source of fouling in convection surfaces. Condensation or precipitation depend upon the temperature regime and chemistry of the fume. The deposit can be in the plastic range and very difficult to remove. On a properly designed and operated unit, this transition of the fume Steam 41 / Boiler Operations
  • 17. The Babcock & Wilcox Company Table 3 Typical Air Flow Splits and Operating Conditions* Firing Technique Stationary Oscillating Firing Firing Primary air 30 to 40% 300F (149C) 3 to 4 in. wg ∆P (0.7 to 1 kPa) 40 to 50% 300F (149C) 1 to 3 in. wg ∆P (0.2 to 0.7 kPa) Secondary air 40 to 50% 300F (149C) 8 to 18 in. wg ∆P (2 to 4.5 kPa) 20 to 30% 300F (149C) 6 to 10 in. wg ∆P (1.5 to 2.5 kPa) Tertiary air 10 to 20% 80F (27C) 10 to 20 in. wg ∆P (2.5 to 5 kPa) 20 to 30% 300F (149C) 8 to 12 in. wg ∆P (2 to 3 kPa) Economizer outlet conditions < 2.5% O2 100 to 200 ppm CO 2.5 to 3% O2 200 to 300 ppm CO * Units with four air levels are discussed in Chapter 28. from a dry gas to a sticky substance takes place in the upper furnace, wide spaced screen or superheater. Here the deposits can be controlled by sootblowers. On an overloaded or improperly operated unit, the gas temperature remains elevated farther back into the closer side-spaced boiler bank or economizer, where controlling the plugging with sootblowing equipment becomes difficult. The gas temperature at which the fume turns to a sticky liquid is also liquor chemistry dependent, with higher levels of chlorides or potassium compounds being detrimental to unit cleanability. The second major cause of plugging is mechanical carryover of smelt, or unburned black liquor, into the convective heat transfer sections of the boiler. This Sound an alarm to clear the area of all unnecessary personnel. Immediately stop firing all fuel-auxiliary fuel and black liquor. Secure the unit’s auxiliary fuel system at a remote location. material is predominantly made of sodium carbonate (Na2CO3), sodium sulfate (Na2SO4) and sodium sulfide (Na2S) compounds. The cause of this carryover is related to operation of the liquor nozzles, oscillators and various air port settings. As previously noted, the black liquor firing equipment and air system settings must produce complete in-flight or wall drying of the liquor droplets. If this drying occurs too high above the smelt bed, the less dense droplets are entrained in the gas stream and carry over into the convection sections of the boiler. In practice, most recovery boiler plugging results from a combination of fume condensation and mechanical carryover. Recovery boilers are also subject to aggressive corrosion compared to conventional fossil fuel-fired units due to the presence of corrosive sulfur, chloride and other trace compounds in an elevated temperature environment. The Kraft recovery boiler also operates in both an oxidizing and reducing atmosphere due to the combustion process. Because of these conditions, the floor and lower furnace walls are constructed using one or a combination of corrosion protection systems: metallic spray coatings or carbon steel tubes, high-density pin studs with refractory, 304L stainless steel tubes, Incoloy® alloy 825 and Inconel® alloy 625 composites tubes, and weld overlay of carbon steel tubes. Smelt-water reactions One unique and undesirable feature of a Kraft recovery boiler is the possibility of water entering an operating furnace through a tube leak or external source, resulting in a smelt-water reaction. A smeltwater reaction occurs when water combines with hot or molten smelt, and a violent explosion can result. This concern has resulted in years of study and testing and has prompted enhanced industry standards on unit design, operation and maintenance. Modern units are equipped with the provisions for an emergency shutdown procedure. This is initiated if water is suspected to have entered the furnace of an operating recovery boiler. Refer to Fig. 7 for procedural overview. Immediately shut off feedwater supply and all other water and steam sources except smelt shatter steam to the boiler. Close primary air dampers and immediately set other air flows to essentially stop combustion and smelting in the bed while maintaining some level of purge air. Regulate induced draft fan flow to maintain furnace balanced draft. Drain the boiler as rapidly as possible to a level 8 ft (2.44 m) above the low point to the furnace floor. Reduce steam pressure as rapidly as possible after the boiler has been drained to this level. Fig. 7 Emergency shutdown procedure overview for an operating recovery boiler (adapted from the Black Liquor Recovery Boiler Advisory Committee, October, 2003). Inconel and Incoloy are trademarks of the Special Metals Corporation group of companies. Steam 41 / Boiler Operations 43-17
  • 18. The Babcock & Wilcox Company Babcock & Wilcox built and operates this refuse-to-energy plant in the southern U.S. 43-18 Steam 41 / Boiler Operations