Air Pollution Control Equipment Services, Emissions

In-situ emissions analyzers provide maintenance-free operation

Issue 5 and Volume 100.

In-situ emissions analyzers provide maintenance-free operation

By John Lauber, Georgia Power Co., and Gerald McGowan, Monitor Labs Inc.

Georgia Power`s Plant Jack McDonough recently installed low-NOx burners to meet Title IV Clean Air Act requirements. The tangential burners at this facility are configured in a symmetric corner arrangement with two adjacent sets of four. Each corner has five burner levels for a total of 40 burners. Therefore, the left and right furnace each contains four burners at five levels for a total of 20 burners. There is a wall between the right and left furnace and the flue-gas streams are either physically separated or virtually independent all the way downstream to the precipitator. The low-NOx burners behave quite differently with respect to load and excess air than conventional burners. To facilitate boiler tuning and to ensure safety, Georgia Power mounted CO and NOx monitors in the flue-gas stream associated with the left and right halves of the furnace. Even though the plant had previously installed dilution extractive continuous emission monitoring systems for compliance purposes, the utility did not extend this system for the CO monitoring application for three basic reasons: (1) it would only measure the composite stream from both units, which would not allow identification of the problematic unit during a boiler upset; (2) with a dilution ratio of 100-to-1 and expected CO concentrations of near 20 parts per million (ppm), the diluted CO concentration is below the range which can be measured accurately by the typical CO ambient analyzer with a range of 0 to 50 ppm; and (3) the maintenance of dilution extractive/fully extractive systems was of great concern.

The other Phase I plants in the system had used extractive systems for CO/NOx monitoring. However, McDonough plant personnel wanted a lower maintenance system for this application. They also wanted to install these analyzers after the air preheaters, but before the electrostatic precipitators. This allows an indoor installation with easy access for maintenance and minimal air in-leakage concerns. As a result, particulate concentrations were very high. Georgia Power first tried an in-situ across-the-stack analyzer which did not work well in this environment. Next, it considered the EX4700 probe type in-situ analyzer offered by Monitor Labs Inc. To evaluate the survivability of the probe and filter in this harsh environment, it first installed a dummy probe in the flue-gas stream for several weeks to determine possible erosion problems. With no problems observed in this test, it then proceeded to install two analyzers, one EX4700 and one SM8175 in the right duct of Unit 2.

The EX4700s measure CO, CO2 and H2O. The SM8175 analyzers measure NOx and SO2. These instruments share a common remote control unit which, with this combination of instruments, can compute and display NOx in units of lb/MBtu. Entering this lb/MBtu value directly into the plant computer control system eliminates the need for additional calculation routines.

Emission control optimization

After four months of trouble-free operation, the plant completed instrumentation of both units, with two sets of the instruments for each boiler. The need to measure CO/NOx was critical in this application since these burners are more finely tuned than conventional burners to maintain low CO and low NOx. By minimizing excess air, O2 levels run from 3 to 3.5 percent and NOx is minimized. However, reducing excess air too much or operating with malfunctioning burners could result in excessive CO, which may ultimately cause explosive conditions. Further, as load and fuels change, it is essential to monitor CO and NOx, in addition to O2, to maintain normal burner operation. Because the units must comply with federal emission regulations, the utility must isolate and correct any problems that develop.

CO concentration levels less than 15 to 20 ppm, wet basis, are indicative of normal operation. If CO increases to 250 ppm, some adjustment is needed. Typically, the flame color and pattern and burner physical adjustments determine which of the burners may be performing improperly. CO levels in the several hundred range are cause for concern, indicating a burner out of adjustment and causing a possible load reduction if NOx emissions are too high.

Since the plant must maintain an emission standard of 0.45 lb/MBtu, the utility entered the NOx emissions in lb/MBtu into the distributed control system and operator displays. From this reading, the operators can diagnose which bank of burners needs adjustment with regard to NOx control. Compared to the old conventional burners, NOx has decreased approximately 40 percent.

Plant performance results

As a result of the burnermodifications, heat rates have increased slightly, primarily for two reasons. First, the boiler is absorbing more heat in the water wall sections and less from the superheaters, which reduces steam temperature. Second, the larger particles in the pulverized coal stream (1.5 percent greater than 50 mesh) are not burning as completely, resulting in greater loss of combustibles [8-percent to 9-percent loss of ignition (LOI)] in the fly ash. The plant has installed a dynamic classifier on one pulverizer to restrict the coal particles to smaller sizes. This is expected to reduce the LOI to 4 to 5 percent once all the pulverizers have dynamic classifiers.

With this complement of flue-gas measurements, the plant has observed other advantages. Georgia Power has used the H2O measurement to diagnose tube leaks. Particularly, H2O measurement can be used to estimate the magnitude of a tube leak and to determine if it is getting worse or if it is stable.

This allows the utility to schedule maintenance at the most advantageous times. The CO2 measurement allows the NOx ppm measurement to be converted to lb/MBtu. Further, in combination with O2, CO2 measurement allows operators to track changes in fuel carbon composition. Similarly, the SO2 measurement provides insight into changes in the fuel sulfur content typically associated with fuel changes.

To date, these instruments have operated largely without maintenance. The instruments operate very well in the high particulate conditions associated with the before-precipitator conditions. (Using SO3 injection, the precipitator performance has improved substantially, with output opacity emissions of 5 to 9 percent). With the probes installed in the high particulate conditions, it is particularly important that the instruments be capable of operating normally with the eventual contamination of the probe-mounted optics. In the course of time, even with 2.5-micron ceramic filter material protecting the internal optical path of the diffusion cells, a film of particulate will collect on the window and reflector surfaces which define the optical measurement cavity. In both of these instruments, a ratiometric measurement technique eliminates the potential error which could result from a decrease in light level–whether from optical contamination in the probe or from the normal lamp/source degradation with time. Thus the collection of fine particulate on the optical surfaces does not preclude the long-term, maintenance-free operation of these probes/instruments. Further, both instruments provide diagnostic indications of light level, allowing the utility to schedule preventive maintenance before the situation becomes critical.

To conserve calibration gases, the above instruments normally operate with an automatic programmed calibration cycle which uses internal span cells or attenuators (electro-optical calibration) as opposed to calibration gases (gas calibration) to check the span calibration of the analyzer. When using calibration gases, the instruments automatically measure and correct both the zero and span values. With electro-optical calibration, the zero value is measured and corrected, but the span value is only measured, or checked. Correction is not provided for the span value since it is does not have the integrity of known calibration gases. Configuring the applications` calibration cycles to activate each six hours minimizes zero-drift errors. Since the CO levels are quite low, this frequent calibration will optimize the accuracy of the measurements. Obviously, when used for Environmental Protection Agency compliance applications, the above instruments are typically set to utilize the gas calibration mode instead of internal span cells.

In this installation, the utility installed a calibration gas manifold at a central location with individual feeds of calibration gas and instrument air plumbed with stainless steel to each analyzer. With this system it is easy to flow single or mixed gas concentrations to any of the analyzers. Because of the instruments` stability, plant managers are considering a gas calibration check as part of their routine maintenance on a monthly or quarterly basis. Each instrument has only one continuously moving part which enhances reliability and maintenance. With the in-situ analyzers, the integrity of the gas sample is beyond challenge, and the dynamic calibration capability with the calibration gases at stack concentrations, temperature and pressure ensures outstanding accuracy. z


John Lauber graduated from Georgia Institute of Technology with a bachelor`s degree in mechanical engineering. Lauber is a senior plant engineer for Georgia Power Co. where he has been employed since 1986. At the Plant McDonough facility, he supervised low-NOx burner conversions and performed boiler/pulverizer optimization during the conversions. In September 1995, Lauber transferred from Georgia Power to the Southern Electric-Birchwood Power facility. Both companies are Southern Co. subsidiaries.

Gerald McGowan graduated from Oregon State University with a master`s degree in electrical engineering. McGowan worked in the aerospace instrumentation field for 10 years before founding Lear Siegler`s Environmental Technology Center in 1971. There he directed the development of instrumentation for emission monitoring and combustion control applications. He was particularly involved in developing Lear Siegler`s in-situ opacity and gas monitoring analyzers. McGowan is currently director of marketing for Monitor Labs, the successor to Lear Siegler`s operations.

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Georgia Power`s Plant Jack McDonough

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The analyzers use probe-mounted optics to measure emissions in the flue-gas stream.

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A remote control unit for the analyzers can compute and display NOx in units of lb/MBtu.