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Industrial Boiler Optimization Toolkit


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The primary function of a utility boiler is to convert water into steam to be used by a steam turbine/ generator in producing electricity. The boiler consists of a furnace, where air and fuel are combined and burned to produce combustion gases, and a feedwater tube system, the contents of which are heated by these gases.

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Industrial Boiler Optimization Toolkit

  1. 1. Boiler Optimization Toolkit
  2. 2. 2 Table of Contents Boiler and Feedwater Pump Efficiency Optimization .................................................................. 3 Accurate Steam Measurement.................................................................................................... 5 Pressure Start-Up........................................................................................................................ 7 Combustion Optimization............................................................................................................ 9 Carbon Monoxide Measurement................................................................................................11 Boiler Life-Cycle Considerations............................................................................................... 13
  3. 3. 3 Boiler and Feedwater Pump Efficiency Optimization Introduction The primary function of a utility boiler is to convert water into steam to be used by a steam turbine/ generator in producing electricity. The boiler consists of a furnace, where air and fuel are combined and burned to produce combustion gases, and a feedwater tube system, the contents of which are heated by these gases. The tubes are connected to the steam drum, where the generated water vapor is drawn. In larger utility boilers, if superheated steam (low vapor saturation) is to be generated, the steam through the drum is passed through superheated tubes, which are also exposed to combustion gases. Boiler drum pressures can reach 2800 psi with temperatures over 680°F. Small to intermediate size boilers can reach drum pressures between 800 and 900 psi at temperatures of only 520°F if superheated steam is desired. Small to intermediate size boilers are only being considered for this application note. With oil‐burning and gas‐burning boiler efficiencies over 90%, power plants are examining all associated processes and controls for efficiency improvements. Between 1 and 3% of the gross work produced by a boiler is used to pump feedwater. One method of improving overall efficiency is by controlling feedwater pump speed to save on pump power. Application Feedwater Flow Control - In electrical power plants, demineralized feedwater is pumped to the boiler tube header. The feedwater flow is regulated by controlling the pump speed by using a process control valve. The normal effect of pure water corrosion‐erosion (or cavitation) that causes premature seat failure within the valve is amplified because velocities of 10+ fps can be reached. Industry: Power Product: DPharp Pressure Transmitter, EJA‐E and EJX‐A series
  4. 4. 4 The added cost of frequent valve replacement makes utilizing a feedwater pump the preferred method of flow control. Controlling pressure by varying the pump speed saves on overall pump power usage. Pump Speed Control - Controlling pump speed is accomplished by variable‐speed electric drives or by close‐coupling a steam turbine to the pump. By definition, cogeneration power plants produce both electricity and excess steam where turbine exhaust is used as a heat source. A steam turbine driven feedwater pump is most often applied because of the abundance of available steam. Boiler Optimization - With a boiler’s firing rate held constant, feedwater pressure and flow affect boiler pressure. As electricity demands change, so do associated boiler loads. When more electricity needs to be generated, the boiler produces more steam, therefore feedwater flow must be increased to the boiler. Significant savings are realized if boiler drum pressure and feedwater discharge pressure are held to a constant differential. This can be accomplished by accurately measuring this pressure differential and controlling the pump speed and feedwater flowrate accordingly. In this example, boiler drum pressures can vary between 800 and 900 psi depending upon the load, (See Figure 2). The feedwater pump discharge pressures can vary between 875 and 1000 psi depending upon boiler demand. Differential pressure between the two points can be up to 200 psi, or even higher in system upset conditions. This differential pressure must be accurately measured, without regard to the 800 psi and above changing boiler drum static pressure. Yokogawa Solution DPharp’s EJA110E and EJX110A “V” range capsule can measure differential pressures up to 2000 psi with the same ±0.055% and ±0.040%, respectively, of span reference accuracy of lower range capsules. In this common application example, ranging the EJA110E V range transmitter 0 to 300 psi allows for the measurement of both boiler pressure and feedwater pump discharge pressure. During pump start‐up severe pressure spikes of 500+ psi can occur which can cause shifts in zero. Many competitors claim re‐zeroing their transmitter at static line pressure minimizes these zero shifts but this task may not be practical under fluctuating pressure conditions. The DPharp transmitter can be bench calibrated and installed into a high static pressure line without re‐zeroing. DPharp is unaffected by these pressure surges due to its superior overpressure protection. The transmitter performance specs are guaranteed over two years. The power plant’s control system can use the high pressure differential measurement to automatically set the feedwater rate depending on the boiler load demand. At lower demand periods, less steam is used to power the steam turbine driven pump and less feedwater is consumed. Significant savings are realized through steam conservation and by lowered maintenance costs with the use of the DPharp transmitter. (Also see Application Note on Boiler Drum Level Measurement PAG‐505)
  5. 5. 5 Accurate Steam Measurement Introduction Steam has often been described as the ‘lifeblood’ of industry. It is the medium by which heat from a boiler is converted into an easily transportable form that can provide diverse services from office heating to the mechanical energy that drives turbine generators. Steam is still one of the most popular methods of providing an energy source to a process and its associated operations. It is now a well-accepted fact that measuring energy consumption is an important factor in the quest to improve energy efficiency. Efficient and accurate metering is paramount to determining excess use, along with an accurate picture of where the steam is being used. A sound energy management policy can only have a positive effect on the ‘bottom line’ profitability. The Challenges Most boiler systems are scalable to the plant’s needs, meaning steam generation can be ramped up or down depending on the need from the facility. This can range from low flows during start up, to higher flows during full operation and back down to low flows during downtimes of maintenance. It is important however that accurate measurement of steam is essential in controlling boiler efficiency and safety. The more accurate and reliable measurements that are made, the more informed decisions can be taken that affect costs and product quality. Traditionally the most common method of steam metering is the orifice plare and differential pressure transmitter technique. General areas of concern with this type of measurement are the orifice plate’s susceptibility to wear introducing immediate inaccuracies, the relatively high permanent pressure losses introduced into the system by the orifice plate and the small measuring range typically 3:1. The orifice flow meter is not suitable for low-flow measurement, and can develop zero drift and span drift when the temperature/pressure conditions fluctuate beyond the design specifications. In order to measure larger turn downs with a orifice, the plates must be changed periodically and the pressure transmitters re-calibrated and spanned. Vortex meters are known to be superior devices for steam flow measurement due to their inherent linear measurement, large turndown, low pressure drop and high accuracy. It is often thought that it is no problem to install a line size meter to capture a wide range of flows but that is not always the case. This practice can lead to losing a lot of the low end measurement. When sizing a vortex meter, it is common to have to reduce the line size using concentric reducers to increase the velocity through the meter for optimum performance. Unfortunately, piping changes need to be made and this can increase costs. Solution To meet the customers’ needs, Yokogawa introduced the digitalYEWFLO Reduced Bore Type Vortex Flow meter featuring a cast stainless steel body and a concentric reducer and expander that enable stable flow rate measurements in low-flow conditions. This expands the range of measurements that can be performed, from the higher flow rates down to the lower end of the flow span, which is normally difficult for Vortex Flow meters, and ensures stable and accurate flow rate output. • Face to face is the same as Standard unit. • Drop in without piping changes Each Flange size available in 3 bore sizes: • Full Bore • 1 size reduction • 2 size reduction
  6. 6. 6 While formerly two to three different types of orifice plates had to be changed to adapt to fluctuations in the line flow rate, this is no longer necessary with the digital YEWFLO reduced bore type. This model reduces installation cost and expands the range of applications available to end user. The flow meter is available with a single reduction or a double reduction in bore size, while still keeping the same face to face dimension of a standard full bore vortex. This makes installations on new projects simplified with no need for additional reducers or piping, and it makes swapping already installed Vortex units simple, as there are no piping changes required. Reduced bore digitalYEWFLO vortex meters are flow tested with the reducers; this ensures the accuracy of the unit is not compromised by reductions in the line. Manual reductions in piping cannot guarantee this accuracy. The main benefits of Yokogawa’s reduced bore type vortex flow meter: • Minimum measurable flow up to five times lower than conventional vortex flow meter. • Integrated construction with reducers built into the flow meter body. • The same face-to-face dimensions ease the task of installing other sizes or types of digitalYEWFLO flow meters. • No need for costly piping modifications such as reducers/expanders or short pipes to achieve the required straight pipe length. • Increases the space for installation of additional instrumentation Yokogawa vortex flowmeters are also well suited to high temperature applications, and the quality of flow management can be improved even further through the use of anti-vibrating efficiency and self diagnostic functions that rely on the digitalYEWFLO’s SSP system. A multi-variable design is also available. With the multivariable option, a built-in integral temperature sensor allows the meter to make a true mass flow measurement of saturated steam by referring to steam tables embedded in the software. This eliminates the need for separate pressure and temperature sensors and a flow computer. Traditional Instrumentation New Instrumentation Using Reduced Bore Type Flow Upstream side 10D Upstream side 5D Down stream side 5D Process piping Reducer Short pipe Short pipe Expander Process piping Process piping Flow Upstream side 10D Down stream side 5D Process piping
  7. 7. 7 Pressure Start-Up Introduction The response time of a pressure transmitter is key to safe and accurate process control. Yokogawa’s DPharp transmitter family features the fastest response time on the market today. Having a faster response time allows for a tighter process control and increased plant efficiency. Fast start‐up and response is crucial for protecting capital equipment, such as compressors, from abnormal or surge conditions. By responding quickly to process changes, compressor flow can be regulated to keep it running at maximum efficiency. Yokogawa’s performance has been evaluated and found suitable for anti‐surge controls. Overall, Yokogawa’s fast start‐up and response time allows for reduced process variability, increased safety, and increased plant availability. Applicable Models EJA‐E Series: All models EJX‐A Series: All models except the EJX910A / EJX930A Response Time The industry definition for Response Time is the amount of time it takes for the output signal to reach 63.2% of the actual pressure change from the time the input change occurs. The 63.2% figure is derived from an equation used for modeling exponential decay rates and represents the output change for the first time constant. Response time consist of two important components, Dead Time and the Time Constant. Total Response Time = Dead Time (Td) + Time Constant (Tc) Dead Time (Td) The response time of a pressure transmitter is key to safe and accurate process control. Yokogawa’s DPharp transmitter family features the fastest response time on the market today. Having a Time Constant (Tc) Time constant consists of the mechanical and electronic response time. Mechanical response time is the time it takes for the process pressure change to be transmitted by hydraulic force to the sensor. Electronic response is the time from the sensor detecting the pressure change to the transmitter electronics producing an output signal. Damping Damping is a setting that allow the customer to increase the dead time of the transmitter. This is done to keep the transmitter from “chattering”. Chattering is when the output signal has small but rapid changes due to process variations. The damping removes this noise by extending the response time. Setting when Shipped Damping is set to 2.0 seconds. The EJA‐E and EJX‐A transmitters are designed to not allow the damping to be set less than 0.5 sec unless the Quick Response feature is turned on. With the feature enabled, the damping can be set down to 0. To achieve the 90 msec response time, the damping must be set to 0. The damping may be set using DTM works in FieldMate. Although FieldMate is highlighted here, any Hart Communicator has access to these functions. Refer to the User’s Manual for the HART programming tree. This function is available in HART 5 or HART 7. Brain Protocol The feature described in this FieldGuide are also available for EJA‐E and EJX‐A transmitters with BRAIN Protocol communication. Please refer to the User’s Manual for details.
  8. 8. 8 Sample Test Results Digital Performance DPharp pressure sensors come standard with two times better installed performance. Yokogawa’s unique digital sensor provides superior performance and stability compared to analog sensor types. Digital sensors also provide stable measurements in all operating conditions. Conclusion With a response time of 90 msec, the Yokogawa EJA‐E and EJX‐A series of smart pressure transmitters are some of the fastest microprocessor based transmitters on the market today. This fast response time allows customers to track process changes more accurately than ever before, thus improving product quality and plant efficiency and safety.
  9. 9. 9 Combustion Optimization What is combustion? Perfect combustion occurs when the correct amounts of fuel and oxygen are combined so that both are totally consumed, with no combustibles or uncombined oxygen remaining in the resulting flue gas. However, fuel may contain impurities and additives to improve viscosity, therefore ideal combustion can only be achieved if all of the following requirements are met simultaneously: • Consistent fuel composition at all times • Pure oxygen in used instead of simple plant air • Complete molecular mixing of oxygen and fuel, at the same temperature and pressure • Unlimited reaction time and zone • Constant in-outlet conditions (pressure, temperature, flow, composition) are maintained • Consistent boiler/furnace load In practice, none of the above requirements are completely achieved due to the physical restrictions in burner design, use of (economical) ambient air rather than expensive pure oxygen, and aging of boiler equipment. When there is insufficient air for combustion control, the fuel is not completely consumed and gives off smoke. This is a sign of energy loss and undesirable emissions. If left unchecked the buildup of combustibles will lead to a safety hazard. On the other hand, if excess air for combustion is supplied, the unused air is overheated and emitted from the stack, causing a heat loss. This increases the emissions of NOx and SO2, which cause air pollution. In order to achieve complete combustion there must be a balance or air-fuel ratio where the boiler is operating as close to zero “excess air” as possible Why Measure O2 ? Either the measurement of oxygen or carbon monoxide can be used to determine the level of excess air. However, measuring CO alone will not define which type of an environment, fuel rich or air rich, a burner is operating in. Therefore combustion control needs to be based on accurate and dependable Oxygen analysis. “Air-fuel ratio” or “Excess air” refers to the amount of air theoretically required to achieve complete combustion of the fuel supplied to the furnace of the boiler. The “air-fuel ratio” or “excess air” is used to achieve the highest efficiency for a system based on each different fuel source. “Excess air” can be obtained by measuring the oxygen concentration in the exhaust gas and calculated by:
  10. 10. 10 Under actual operating conditions some amount of excess air is always necessary to bring the combustibles level close to zero. The challenge is to minimize these effects by achieving completed combustion with the lowest excess air levels possible. It is important to accurately measure and control oxygen analysis because: Insufficient air is a waste of fuel which is a waste of money. As a rule of thumb each 10% excess O2 is equivalent to a 1% in wasted fuel. • To minimize heat loss since the more excess-air used, the more heat required to warm it prior to combustion resulting is wasted heat contained in the waste gas carried to the stack. • Optimizing fuel consumption by maintaining complete combustion. • Minimizing power consumption by ancillary devices (air blowers; damper positioners). • Reduction of air pollution since a surplus of excess air at high temperatures allows for the formation of SO2, SO3 and NOx from the fuel impurities and air-nitrogen. What products would I use? Application Notes 1. Boiler Control Solution Instruments and Solution for Automatic Boiler Control 2. Air Leak Detection in Sintering Furnaces to Enhance Efficiency and Product Quality 3. Measurement of O2 Concentration in Exhaust Gases from Pulverized Coal-fired Boilers 4. Measurement of O2 Concentration in Hot Blast Stoves 5. Oxygen Concentration in Package Boiler Flue Gases Oxygen Analyzer Products Oxygen Analyzers Specifically for Package Boilers: Integral Oxygen Analyzer ZR202
  11. 11. 11 Carbon Monoxide Measurement Background Information There are currently 1470 generators at 617 facilities in the United States alone that use coal as the major source of energy to generate electricity. Of these facilities, 141 are considered industrial, institutional or commercial sites that consume most of the electricity produced on-site. The remaining 476 sites are identified as “power plants” owned by electric utilities and independent power producers that generate and sell electricity as their primary business1 . The primary goals that drive these power plants are increasing efficiency and throughput, reducing emissions of pollutants, and maintaining a high level of safety. Obtaining these goals ensures that the power plants generate the highest profits, while complying with environmental regulations and assuring workplace and community safety. Introduction An accurate measurement of the carbon monoxide (CO) concentration in the boiler flue gas can be used to achieve the goals of combustion efficiency, pollutant emissions reduction, and safe operation. By measuring the concentration of CO, power plants are able fine tune the air to fuel ratio used on the burners to obtain the highest combustion efficiency. Measuring the CO concentration allows the power plants to reduce the amount combustion air used while ensuring complete combustion, reducing the production of the pollutant NOx. The concentration of CO in the flue gas is also the most sensitive indicator of unburned combustibles in the process and can indicate the emergence of an unsafe situation. Efficiency, Emissions, Safety Given complete mixing, a precise or stoichiometric amount of air is required to completely react with a given quantity of fuel to produce complete combustion. In real world applications, conditions are never ideal so additional or “excess” air must be supplied to completely burn the fuel. Too little excess air will result in a “fuel rich” situation producing a flue gas containing unburned combustibles (carbon monoxide, soot, smoke, coal). This situation results in a loss of efficiency because not all of the potential energy of the coal is captured in the combustion process resulting in fuel wastes. Combustion processes that run fuel rich are “running dirty” meaning an increase in pollutant emissions. Also, this is not a safe situation as the unburnt fuel could possibly come into contact with an ignition source further down the process resulting in an uncontrolled explosion. Too much excess air results in an “air rich” situation, resulting in complete combustion and safety, but also produces undesirable effects. Efficiency is lost in an air rich process because the increased flue gas flow results in heat loss. More fuel is required to generate the same amount of heat, so fuel is wasted in this low “boiler fuel-to-steam” efficiency situation. Since air is comprised of over 78% nitrogen, increasing the air used for combustion significantly increases the concentration of nitrogen. Nitrogen exposed to temperatures above 1600°C (2912°F) may result in the formation of “thermal NOx” (NO, NO2). These substances are major contributors to the formation of acid rain and their release into the atmosphere is heavily regulated by environmental agencies. The ideal situation is to provide just enough excess air to produce complete combustion, but not any more than that. This will produce the highest efficiency, lowest emissions of pollutants, and maintain a high level of safety. The question is: How is the excess air setpoint determined? Using CO to trim excess O2 The amount of excess air in the flue gas is determined by measuring the concentration of oxygen (O2). The ideal excess O2 level (the lowest possible that allows complete combustion) depends on several factors: the fuel type, the burner type, humidity changes in the air, moisture content changes in the fuel, varying boiler loads, fouling of the burner system, and mechanical wear of combustion equipment. Since many of these factors are continuously changing, the ideal amount of excess oxygen continuously changes as well. Measuring carbon monoxide (CO) can help to determine the excess oxygen setpoint. CO is the most sensitive indicator of incomplete combustion. As the amount of excess O2 is reduced, the emergence of CO will occur before other combustibles appear (unburnt fuel). When the concentration of CO reaches the desired setpoint (typically around 400 ppm), the excess O2 concentration is at the desired level and becomes the new excess O2 setpoint. As the concentration of CO increases or decreases, the excess O2 setpoint can be trimmed accordingly. CO trim control of excess O2 concentration assures minimal energy loss, maximum efficiency, and reduced NOx emissions independent of boiler load, fuel type, humidity, moisture content of fuel and other variables that make excess O2 control difficult. The key to obtaining these benefits is an accurate and reliable measurement of CO in low ppm levels. 1. Source: Department of Energy Website (
  12. 12. 12 Obstacles to Measuring CO in Coal Fired Boilers Measuring CO accurately and reliably in coal fired applications has traditionally been extremely challenging. Some of the obstacles that must be overcome: • Flue gas laden with fly ash particulate • High temperature in the optimal measuring location • Stratification of gas concentrations • Presence of SO2 in the flue gas • Speed of response in non-insitu installations Current measuring technologies that are employed to measure CO (or combustibles in general) are Catalytic Bead sensors, Thick/Thin Film thermistors, and IR spectroscopy. The Catalytic Bead and Thick/Thin Film thermistors utilize the thermal properties of combustion to change the resistance of an active element compared to that of an inactive reference element. The active element is coated with metal that acts as a catalyst for combustion when exposed to air and a hydrocarbon. The other element is left in a natural state without a coating to act as a reference against background changes that would affect both elements (i.e. process temp, gas thermal conductivity etc). Combustion on the surface of the active bead increases the temperature of the bead in effect raising its resistance. The difference between the reference and active resistance values is proportional to the concentration of combustibles in the process gas. Infra-red Analyzers use an infrared source mounted directly on the flue gas duct or stack on the side opposite from the receiver. Infrared energy is radiated by the source, through the flue gas, to the receiver. The receiver employs gas filter correlation and narrow band pass optical filtration with a solid state detector to determine the absorption of radiation by CO in the flue gas. The magnitude of the absorption is proportional to the concentration of CO in the flue gas. Catalytic Bead Sensor Infrared Analyzer These measuring technologies are prone to the following problems: • The catalytic sensors require sample extraction (not insitu) installations. These sample extraction systems are prone to plugging and fouling with fly ash in coal fired applications. They require frequent preventative maintenance and the filters they require cause slow response times. • The catalytic sensors are discreet or point measurements. They do not provide a path or average measurement across the firebox. They are subject to stratification errors, may not detect isolated areas of CO breakthrough, and require multiple points of installation to provide adequate coverage. • IR analyzers cannot make the measurement in particulate laden (fly ash) flue gas. This combined with temperature limitations prevents IR installation directly across the fire box. They must be installed further down the process, at lower temperatures after particulate removal (precipitators). This introduces more lag time in detecting CO breakthrough. Also CO that reacts after the fire box will not be detected (CO quenching). • IR analyzers are subject to interference from CO2 and water. Catalytic sensors are subject to interference from NO2 and water, and quickly deteriorate in the presence of SO2. This mandates frequent calibrations, replacements, and suspect accuracy. • These problems prevent these traditional measurement technologies from providing an accurate and reliable CO measurement. • Solution to Measuring CO in Coal Fired Boilers • Tunable Diode Laser Spectroscopy (TDLS) manufactured by Yokogawa Corporation of America has been proven in the field to be a solution for this difficult measurement. Tunable Diode Laser measurements are based on absorption spectroscopy. The TruePeak Analyzer (TDLS200) is a TDLS system and operates by measuring the amount of laser light that is absorbed (lost) as it travels through the gas being measured. In the simplest form a TDL analyzer consists of a laser that produces infrared light, optical lenses to focus the laser light through the gas to be measured and then on to a detector. The detector and electronics that control the laser then translate the detector signal into a signal representing the CO concentration. • The TruePeak Analyzer utilizes powerful lasers that are highly sensitive and selective for CO. This results in many benefits over traditional IR analyzers and catalytic sensors: • The TruePeak Analyzer measures CO directly in the fire box. This means no lag time in detecting CO breakthrough and no false low reading due to CO quenching after the fire box. • The TruePeak Analyzer measures CO insitu. There is no extractive sample system induced maintenance or lag time. • The TruePeak Analyzer is a path (across the fire box) measurement. This provides an average reading that ensures isolated areas of CO breakthrough are detected. Multiple installations are not required. • The powerful, selectable laser of the TruePeak Analyzer penetrates fly ash and is sensitive to low ppm levels of CO. Summary Coal fired power plants can achieve the highest efficiency, lowest emis- sion levels, and ensure safety by using CO concentration measurements to fine tune their excess O2 setpoint. These benefits are achievable only if the CO measurement is accurate and reliable. Using TDLS, the TruePeak Analyzer from Yokogawa can provide that accurate, reliable CO measurement in coal fired power plants. Product Recommendations The TruePeak Analyzer - Model TDLS200 Flue Gas Stratification
  13. 13. 13 Boiler Life-Cycle Considerations Whether a boiler should be repaired or replaced is largely dependent on age and condition. Proper monitoring of water quality (pH, Cond, DO), chemical addition control (ORP), and real time corrosion control (ECP). Regular maintenance is important to prolonging the life of a boiler. However continuous of monitoring of water quality allows for predictive maintenance and prevention of shutdown. Where and what should be monitored? For the Pure Water applications, the primary measurement we encounter is conductivity but we have offered pH/ORP, and Dissolved Oxygen configurations as well for over 15 years with great success. Quick Run Down of Applications: • Reverse Osmosis Filters • Conductivity: Ratio or % Passage/Rejection (two sensors) • pH occasionally, for membrane life • Demineralizers: • Cation, Anion, Mixed Bed • Cation • Cation Conductivity (two sensors in ratio) • Charged Cation Beads “remove” (change to acid) positive Ions and release H+ into stream • Cation Conductivity has special Temp Comp to take the H+ into account • % Concentration (1 sensor) • Beads are regenerated with acid (typically HCL or H2SO4) • Anion • Specific Conductivity (1 or 2 sensors) • Charged Beads “remove” (change to water) negative ions • % Concentration (1 sensor) • Beads are regenerated with Caustic (NaOH) • pH occasionally • Completeness of after-regeneration Rinse • Mixed Bed (“Polisher”) • Specific Conductivity (1 sensor) • Removal of both +/- Ions (“fine” cleaning, < 0.1 uS/cm) • pH occasionally for complete monitoring • Deion Storage • Specific Conductivity (1 sensor) • Ensure Water Quality after storage • Second Polisher • Specific Conductivity • Final cleaning (Boiler applications)
  14. 14. 14 To defray energy costs, many industrial plants have their own boilers to generate steam to produce a portion of their energy needs. In addition, the steam may also be used directly in plant processes or indirectly via heat exchangers or steam jacketed vessels. The Problem for this application is that the raw water used to feed the boilers, contains varying levels of impurities that must be removed to protect the boiler and associated equipment. Pretreatment processes such as reverse osmosis, ion exchange, filtra- tion, softening and demineralization may be used to reduce the level of impurities, but even the best pretreatment processes will not remove them all and there will be a continuous carryover of some dissolved mineral impurities into the boiler. Boiler feed water usually contains one limiting component such as chloride, sulfate, carbonate, or silica. Even if the component is not conductive, for example silica, its concentration is usually proportional to a component that can be measured by conductivity; therefore, conductivity is a Tech Note: TNA1409 Date: August 20, 2014 viable measurement for monitoring the overall total dissolved solids present in the boiler. A rise in conductivity indicates a rise in the “contamination” of the boiler water. So, measuring conductivity of the feed water is important to this application. The most common methodologies used for boiler blowdown control include: (1) continuous, (2) manual and (3) automatic. Continuous blowdown utilizes a calibrated valve and a blowdown tap near the boiler water surface. As the name implies, it continuously takes water from the top of the boiler at a predetermined rate to reduce the level of dissolved solids. The rate is usually set slightly greater than necessary to be on the safe side. Manual blowdown is accomplished at most plants by taking boiler water samples once a shift and adjusting the blowdown accordingly. This grab sample approach means that operators cannot immediately respond to changes in feedwater conditions or variations in steam demand and scaling conditions can occur and go undetected until the next sample check. Automatic blowdown control is achieved by constantly monitoring the conductivity value of the boiler water and adjusting the blowdown rate and duration based on a specific conductivity set point. This provides control of the water chemistry regardless of the boiler load conditions. Actual operation data verifies that automatic control can maintain boiler water conductivity consistently within 5% of the set point. Manual blowdown control cannot maintain this level of control more than 20% of the time. Again, measuring conductivity is essential for controlling this application.
  15. 15. 15 Want more detailed information? Application Notes 1. AN10B01B02‐10E‐A: Reverse Osmosis 2. AN10B01B02‐21E‐A: Pure Water pH 3. AN10D01P01‐01E: Boiler Leak Detection 4. SC‐A‐002: Demineralizer 5. SC‐A‐004: Boiler Blowdown Technical Information 6. TNA0915: Care and Maintenance of a High Purity pH System 7. TNA0916: Proper Calibration 8. TNA0918: Maintaining Yokogawa pH Monitoring System 9. TNA0923: Sensor Diagnostics 10. TNA0925: Wet vs Dry Electrodes
  16. 16. Calgary, Canada Newnan, GA Headquarters: Sugarland, TX Mexico City The contents of this document are subject to change without prior notice. All rights reserved. Copyright © 2015 Yokogawa Corporation of America. Printed in USA Submit an Inquiry If you are looking to get a quote, resolve a technical support issue or just need to contact Yokogawa, please fill out our web form and we will be in touch shortly. Locate your Sales Representative View our interactive map or enter your postal code to locate the sales associate(s) in your area. Find a Yokogawa Office Browse our North American main offices. You can find fax and phone numbers, mailing addresses and maps of our office locations in Canada, Mexico, and the United States. If you have questions or need more information, we have a wealth of resources ready to help you. Select one of the options below or if you prefer, just give us a call at 1-800-888-6400.