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 generatethe 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.
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
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| Catalytic Bead Sensor |
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.
These measuring technologies are prone to the following problems:
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| Infrared Analyzer |
- 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
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| Flue Gas Stratification |
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 emission 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.
Industries
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Power
In the mid 1970s, Yokogawa entered the power business with the release of the EBS Electric Control System. Since then, Yokogawa has steadfastly continued with the development of our technologies and capabilities for providing the best services and solutions to our customers worldwide.
Yokogawa has operated the global power solutions network to play a more active role in the dynamic global power market. This has allowed closer teamwork within Yokogawa, bringing together our global resources and industry know-how. Yokogawa's power industry experts work together to bring each customer the solution that best suits their sophisticated requirements.
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In-Situ Gas Analyzer TDLS200
The TDLS200 is designed to make fast, accurate measurements of gases including oxygen (O2), carbon monoxide (CO), methane (CH4), moisture (H2O), carbon dioxide (CO2), ammonia (NH3), and hydrogen chloride (HCl). It is ideally suited for environments involving changing pressure or temperature.