The operation of a boiler and its auxiliary equipment requires the constant exercise of intuitive reasoning and sound engineering judgment. It is in operation that all of the factors that went into the design and construction of the system are put to the test.
The proper instrumentation, control logic, and control system
are required to assist the operation personnel in performing safe, efficient, and reliable operation. Process control, performance diagnostics, and condition monitoring are key technologies used to decrease or mitigate uncertainties.
These technologies address three requirements:
These requirements may share the same data bias. It is in the hands of the operator to use wisdom, knowledge, and experience to achieve these requirements simultaneously. Certainly, if a common ground can be reached among these three requirements, the operator’s job will be easier and a better chance exists to achieve each singular requirement. The ideal case is that the operating control also achieves
performance optimization without causing deterioration to the components. It is difficult to reach this ideal condition with current practice because each system control has its own evolution history. It will take advanced techniques, experiences, and detailed understanding of the interrelationship among these systems to reach a common goal. Certainly, it is the future challenge and focus to integrate and consolidate these procedures.
The preservation of boiler operation and performance includes meeting underlined design assumptions and process control. The boiler design involves the energy balance between the fireside and the steam side parameters. In a typical fossil power plant, there is more steam side instrumentation installed with the original control system than there is flue gas side instrumentation. However, the fireside provides the heat energy input to the boiler system and it is extremely important to control the fireside operating parameters to ensure the boiler performance. Typically, the boiler lacks fireside control. The fuel and air are mixed, combustion takes place in the burner system and the next monitoring point in the flue gas path is the boiler exit temperature. Basically, there is nothing in between. There is a simple logic to converting from a two point control, burner and boiler exit temperature, to a three point control; i.e., burner, furnace exit gas temperature (FEGT), then boiler exit temperature. This extra control point, FEGT, can have a major impact on boiler performance and reliability.
Basically, the furnace exit point separates the radiation zone from the convection pass. FEGT is one of the most important interface parameters in boiler design and operation. Typical boiler gas side design involves the following considerations:
The FEGT can be affected by the following operational parameters:
A furnace startup probe is sometimes used to protect the superheater and reheater tubes prior to the establishment of steam flow. Unfortunately, the current startup probes can not be used for the complete flue gas temperature range. For many years the utility industry has been actively involved in developing more accurate instrumentation, analysis methods, and performance improvement techniques for the fire side parameters control. There are many techniques that can be used to obtain the FEGT on-line, i.e., direct measurement or from calculations. Direct measurement techniques can be intrusive and non-intrusive. Operators can use this information to balance combustion.
FEGT control is a critical parameter which can be used to preserve the boiler operation and performance including, emission, reliability, and safety. If FEGT deviates from the design value the following undesired condition can occur:
Increased slagging/ fouling of water walls, superheater, and economizer, and air heaters Increased corrosion rates of superheater and reheater tubes Potential of convective pass tube overheating (creep damage), requiring more attemperation Altered design conditions which are more difficult to correct by the operator Increased flue gas temperature in the boiler exit which increases heat loss and lowers efficiency FEGT provides an operational safeguard and indictor for the boiler operation.
The following influential factors will be discussed:
One of the important characteristics of the fuel from a boiler design view point is the slagging and fouling control. The formation of slag deposits is caused by the deposition of molten ash on surfaces receiving heat by radiation such as the furnace and radiant sections of the supereheater. Entrained in the gas stream, molten ash particles strike the wall or tube surface becoming chilled then solidify. If slag is allowed to accumulate on the lower furnace walls, furnace exit gas temperature will rise and the slagging area is forced higher into the furnace. The effect on the furnace performance can be drastic. Proper boiler operation requires keeping the ash particles away from the walls and in suspension in the gas stream until the ash is sufficiently cool to be admitted to the convection pass.
Parameters that result in increased deposition include:
Maintain the hot furnace can reduce the furnace slagging problem. Limiting FEGT to a minimum 100oF below the ash softening temperature can substantially improve the convective pass fouling problem, because the dry ash leaving the furnace will not stick to the steam tubes. If the fouling and blockage in the convective pass is reduced, the superheat soot blowing and fan power can be reduced which improves the heat rate. It also prevent soot blower erosion.
If the coal being burned is changed, the ash fusion temperature for new coals can be obtained from the laboratory test or can be provided by coal suppliers. A new FEGT limit can be established by the operator and to adjust other operational parameters to minimize the potential of slagging/ fouling. As a pre-requisite, the combustion system should be tuned to achieve the following:
The furnace exit gas temperature (FEGT) in a utility boiler is a critical parameter which requires monitoring during boiler start-up and on-line operation. Start-up FEGTs must be controlled so as not to exceed allowable superheater tube metal temperatures. Many fossil plants use air-cooled probes, which must be retracted when temperatures reach 1,000 degrees F. Maintaining the FEGT within the design limit during the normal operation can ensure boiler operability, thermal performance and boiler reliability. The problem in the past is the lack of on-line instrumentation to measure the high flue gas temperature. Water-cooled HVT probes have been used for many years to measure gas temperature above 1,000 degrees F. Because of the probe length and weight limitations, HVT is used primarily for testing purposes and not for continuous operation.
An infrared system has been developed to measure the flue gas temperature. The patented system has the trade name of Infra-View®Infrared Thermometers. The infrared Infra-View®sensor detects the heated CO2 gas created in a boiler or furnace as a product of the combustion process when fossil fuels are burned. The infrared spectral response of the Infra-View®sensor is preset specifically to detect CO2 infrared energy by using a thin film thermopile with a spectra filter designed to block out all other wavelengths of infrared emissions. Since the Infra-View detector is sensitive to only the hot CO2 gas spectrum, it can measure temperature of the CO2 gas directly within the field of view.
Infra-View®Infrared Thermometers are remote sensing infrared detectors that are permanently flange mounted on any port, door or penetration into the boiler or furnace. It is a lightweight device and can also be used as a portable system for testing purposes. The Infra-View®patented design is supplied with a rugged protective-cooling jacket that is factory assembled and pre-piped with an air cooler, purging and filtering system designed to work in most severe service environments. Customer supplied compressed air and two wire shielded signal cable is all that is necessary for operation when integrated in a 4-20mA signal loop supplied from a DCS, digital or analog recording device. The Infra-View®infrared “non-contact” sensors monitors flue gas temperatures in the boiler or furnace ranging from 250 degrees F. (120° C) to 3000 degrees F. (1,650° C). Higher end temperature measurements are also available.
The Infra-View boiler thermometer is a passive infrared detector that senses boiler gas temperature from 250ºF to 3000º F when integrated in a 4 – 20 mA signal loop from any digital or analog device. The heated CO2 gas is at a molecular level of excitation that becomes detectable through this method of infrared remote sensing. As the temperature in the boiler increases, CO2 gas excitation increases concomitantly in this infrared spectrum.
The proprietary infrared spectral response of the Infra-View thermometer is pre-set specifically to detect infrared emissions from hot CO2 gas. This is accomplished by filtering out all other wavelengths of infrared energy. Modern infrared thermometry has advanced significantly with the use of “selective filtering” of the incoming infrared signal. Specifically, selected narrow band spectral responses are necessary in order to see through atmospheric interferences in the sight path, to obtain a measurement of gas or other substance which is transparent to a broad band of infrared energy.
Infrared radiation is observed as emitted from excited molecules of gases. Many of the energy transitions which take place in gases excited thermally or electrically result in radiation emission in the infrared region. Gaseous emission differs in character from solid emission in that the former consists of discrete spectrum lines or bands, with significant discontinuities, while the latter shows a continuous distribution of energy throughout a broad band spectrum.” Gases such as CO and CO2 exhibit a strong but narrow infrared spectral response that can be detected with sensitive infrared sensors utilizing the specific spectral filter.
Since CO2 gas is a by-product of the combustion of all fossil fuels, its unique spectral response was selected because of its applicability to all boilers and furnaces regardless of the fuel burned. With a concentrations of CO2 gas typically found in fossil fuel burning utility and industrial boilers, there is a high enough level (10 – 12%) to reach a threshold of detection where the Infra-View sensor can measure the average or peak temperature directly within the field of view of the instrument. Because the Infra-View “sees” the CO2 gas within the boiler as semi-transparent or opaque medium, within the conical field of view (30:1) the largest volume of gas molecules are oriented farthest away from the sensor. Hotter gases, because of the selective spectral filter, are favored over the cooler gases located nearer the sensor comprising a smaller volume in the field of view. As a consequence, the Infra-View will sense heated flue gas in the boiler yielding a temperature reading that is indicative of the overall boiler environment. Secondly, the quick response time (100 msec.) when averaged over say, 10 seconds (100 readings in all) generates a representative temperature reading of the dynamic upward flow of heated gases past the sensor posting the processed data in a time vs. temperature relationship.
The Infra-View®”smart” sensor can be programmed to measure the average or peak temperature directly within the field of view of the instrument. The Infra-View® Boiler Thermometer will measure gas temperature across the boiler or furnace, however, when the line of sight is directed at the fireball, the Infra-View®will only measure the temperature of the fireball flame due to extremely high concentration of CO2 gas generated there. Average temperature readings are particularly useful in the superheat, reheat and convection passes because boiler flue gasses tend to be vertically stratified in terms of temperature. As a consequence, the temperature reading will be the average value of all the vertical stacked gas temperatures in the field of view of the Infra-View®. This is indeed a more useful value, when compared to measuring a point source at a given depth with say, an HVT probe. Point source measurements are certainly not indicative of the overall temperature profile in the boiler. Peak temperature readings are most applicable for start-up control.
Ostensibly, average readings are arithmetic mean value of the peak (highest) and valley (lowest) reading processed over programmed duration in the “smart sensor”. Peak readings are actually a peak hold reading that stores the highest temperature over a predicted time interval or duration. Should the “smart sensor” measure a temperature higher than the one currently displayed, it immediately updates the display and starts a new time interval. Should the “smart sensor’ see no temperature above the one presently displayed, it will hold this value until the duration expires.
The Infra-View® Boiler Thermometer “smart sensor” can provide a flue gas temperature reading with an accuracy of 1% of reading. Primary signal processing occurs within the Infra-View® Boiler “smart sensor”. For average and peak readings based on a 100 msec. response time, a temporal component can be programmed, by processing the output signal posting time from 1 to 60 seconds.
Through empirical testing, we have discerned that the Infra-View® Boiler Thermometers most applicable flue gas temperature readings can be acquired through the use of the Peak Hold “smart sensor” function combined with additional signal conditioning within a distributed control system (DCS).
Infra-View®peak readings with a 10 second hold, are transmitted to the DCS via a 4 – 20 mA analog output. Within the DCS, these outputs are further digitally filtered or conditioned with internally stored algorithms. The two most germane algorithms are a smoothed value transform (smoothing function) or the running average transform (run average mode).
Smoothing Function: Smoothing of an analog input consists of giving the most weight to the most recent sample and the diminishing weight to all preceding readings. The relative weight given to the most recent value is determined by the smoothing time constant specified for input filtering.
Run Average Mode: The analog input is sampled periodically as specified by the user from the Number of Units and the Units of Time Fields. An average reading of all data is posted based on first in last out data stream.
A conditioned output signal is displayed in Figure 1 demonstrating real time temperature data from the Infra-View® Boiler Thermometer fed into a DCS and filtered in order to generate a “smooth” temperature curve that can be utilized for control.
These “smoothed” output signals can then be utilized for automation of control valve operation during start up; soot blower control; ash fusion control; superheater high temperature annunciation and numerous other functions such as SNCR enhancer addition which is extremely temperature dependent.
The preservation of boiler operation and performance requires proper fireside operating fireside control. Basically, the existing boilers are lacking of proper fireside control. The fuel and air are mixed, combustion takes place in the burner system and the next monitoring point in the flue gas path is the boiler exit temperature. It is recommended that the process be converted from two point control, burner and boiler exit temperature to three point control; i.e., burner, FEGT, then boiler exit temperature. This extra control point,, FEGT, can have a major impact on boiler performance and reliability. The Infra-view system provides wide range flue gas temperature measurement and is a low cost effect instrumentation to measure the FEGT on-line. The system has been demonstrated successfully in more than 500 sites to provide real-time information for boiler operation, performance, and reliability improvement.
Note: Technical authors and references available upon formal written request.
Source: JNT Technical Services Inc.
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