Doug Simmers here again, discussing flue gas analysis, and it’s operational value for boilers and industrial furnaces. Controlling the amount of air going into any combustion process is important in maximizing the efficiency of the furnace.
It’s pretty easy to see why a fuel-rich mixture is inefficient, since unburned fuel goes out the stack without giving up its heat value. Besides being inefficient, the accompanying black smoke also draws the neighborhood’s attention, and operation in this mode is also unsafe.
The disadvantages of operating with too much air (lean) is not as obvious. After all — air is free, isn’t it? Since air is invisible, it’s easy to forget that it has mass, as sticking your hand out the window of a moving car demonstrates. The energy required to heat up air is called its specific heat (0.24 BTU/lb/degree F), and any air that is not used for burning the fuel merely cools off the flame. Granted, this excess heated air gives back some of its heat in to the boiler tubes, but it almost always exits the stack at a temperature significantly above the temperature it goes into the burner. This heat is lost forever, and if one considers the significant volumes passing through the furnace, this loss can be significant. Further, an excess oxygen reading of 1% is the smaller amount of gas that is being heated up, since it’s only about a fifth of the total volume of air (20.95% O2). So a small increase in excess O2 increases the total air going through the furnace significantly. Additionally, it costs money for the fan blowing air into the burner to move this excess air, and it also reduces the total amount of steam the boiler can produce.
In the previous blog, we discussed how the ideal O2 setpoint is arrived at by detecting the point of CO breakthrough, but how do we determine how important running at the optimum level is? A blog is not the ideal place to run down the ASME short form calculations, but our Jim Thompson has developed a neat program that calculates this out for you (note that most utilities use more comprehensive calculations for determining heat rate). http://www2.emersonprocess.com/en-US/brands/rosemountanalytical/Gas/combustion-flue-gas-analyzers/OXT5A/Pages/O2_TrimCalculator.aspx
The procedure is to determine the “as found” operational condition of the boiler, and then determine how much lower in oxygen the boiler or furnace can operate. The payback is the final output — a great tool for justifying a project.
Next time we’ll discuss how to use the oxygen measurement to minimize the thermal NOx produced in a burner.
Until then, let me know what you think! Post any comments or questions here!
Pete Anson here. In today’s blog, I’m discussing temperature correction in conductivity measurements. A few customers have inquired about this topic, so thought it might be useful to discuss. Conductivity depends on both ion concentration and temperature. To reduce the influence of temperature on the measurement, common practice is to measure the raw conductivity and temperature and calculate what the conductivity would be at a reference temperature, typically 25°C. Clearly, the calculation requires making some assumption about the liquid being measured.
Below, I describe the temperature compensation algorithms commonly available in process conductivity analyzers. I also give examples where the correction is appropriate and some of the pitfalls associated with each algorithm.
Using these guidelines, users can make reasonably accurate conductivity measurements in most applications. What have been your experiences with temperature compensation?
G’day y’all – Shane Hale here again from Gas Chromatographs. At the end of January, I had the honor of presenting at the Natural Gas Sampling Technology conference (NGSTech) held in New Orleans (they even have a photo of me speaking in 2008). This two-day conference focused exclusively on the latest developments and challenges in the field of natural gas sampling for both spot samples and online analyzers.
Just about every single paper presented at the conference mentioned the importance of the hydrocarbon dew point of the sample gas when designing or operating a sample system. (This being in New Orleans, there was even a suggestion to start a drinking game around the term!) My paper dealt with the issues that the hydrocarbon dewpoint of the sample can cause when using a gas chromatograph. I discussed how you can use the hydrocarbon dew point calculation in our C9+ gas chromatographs to calculate the hydrocarbon dewpoint at the pipeline pressure to provide an early warning of two-phase flow and avoid inaccurate flow measurement (see Fig. 1).
I then discussed the effect that poor sample handling can have on the analysis. I have a real-life example that I use all the time that shows the effect of the analysis when the heavy hydrocarbons drop out as the sample line temperature drops at nighttime (see Fig. 2). In this example, the heat trace was turned off.
And this is where it got interesting. I’m standing there on stage, in front of over 180 people, and an idea comes to me. We can calculate the hydrocarbon dew point at up to four pressures. The regulated sample pressure is controlled to around 20PSI G/1.4BarG. What if we calculate the hydrocarbon dew point of the sample at the regulated sample pressure, and compare this to the ambient temperature? If the hydrocarbon dew point is the same as (or very close) the ambient temperature, it means that the sample has dropped out some of the heavy components into the sample system. (see Fig. 3)
If the heavies have dropped out, then the GC is no longer analyzing the same gas as what is in the pipeline. If the GC is not analyzing the same gas that is in the pipeline, then energy calculations and flow calculations will be incorrect, and thus the custody transfer measurement will be incorrect. This must have been a good idea, as the audience clapped at the end of my presentation, and quite a few people came up to me to discuss this in the exhibition hall later that day.
Wow. What a concept: online determination of the sample system performance. After the conference, I went back to my office and fleshed this out a bit. By entering the nominal regulated sample pressure into hydrocarbon dew point calculation as a fixed value, the C9+ Gas Chromatograph will provide the dew point of the gas in the sample lines. An ambient temperature transmitter can be connected to the analog inputs of the 700XA C9+ GC (for the Model 500, the second detector on the C9+ HCDP application uses the analog inputs) or the ambient temperature downloaded to the controller via modbus. A user calculation can then compare the values and if they are within a certain tolerance (e.g. 10°F), the controller can raise an alarm to highlight an issue in the sample system (for example, the heat-trace is turned off or not installed).
In practice, the comparison of the sample pressure hydrocarbon dew point and the ambient temperature is best done in the flow computer or the SCADA system, as they have better alarming and trending capabilities than the gas chromatograph, but the concept is the same. The ability of a C9+ gas chromatograph to calculate the hydrocarbon dew point on multiple pressures give us new online diagnostics to help us operate our custody transfer metering systems.
’till next time,