By Amanda Gogates, Product Manager for Quantum Cascade Laser Analyzers, Emerson Process Management
You may have seen a few stories already on the innovative QCL laser technology. That technology has now been successfully implemented in Emerson’s Rosemount™ CT5100 continuous gas analyzer. It is the world’s only hybrid analyzer to combine Tunable Diode Laser (TDL) and Quantum Cascade Laser (QCL) measurement technologies for process gas analysis and emissions monitoring. The CT5100 provides the most comprehensive analysis available (down to sub ppm) for detecting a range of components, while simplifying operation and significantly reducing costs. The CT5100 can measure up to 12 critical component gases and potential pollutants in a single system – meeting local, state, national, and international regulatory requirements.
But if you’re thinking that the CT5100 is remarkable but “bleeding edge” technology that your application can’t afford – think again. The Rosemount CT5100 operates reliably with no consumables, no in-field enclosure, and a simplified sampling system that does not require any gas conditioning to remove moisture – truly “next generation” technology which saves you money at every turn. The CT5100 is a unique combination of advanced technology and rugged design, and is highly reliable. Its patented laser chirp technique expands gas analysis in both the near- and mid-infrared range, enhancing process insight, improving overall gas analysis sensitivity and selectivity, removing cross interference, and reducing response time. This laser chirp technique produces sharp, well-defined peaks from high resolution spectroscopy that enables specificity of identified components with minimum interference and without filtration, reference cells, or chemometric manipulations.
The rugged Rosemount CT5100 analyzer features –
Give your Emerson representative a call and discuss the potential of the CT5100 in your process gas analysis, continuous emissions monitoring, and ammonia slip applications. This could be a whole new solution to some costly problems. Click HERE for more information on the CT5100.
By Iliana Colín, Emerson Gas Specialist for Analytical Measurements
Hello, I’m Iliana Colín and I’m your Analytic Expert today. I’d like to talk about some of the challenges associated with catalyst regeneration in catalytic cracking and how rethinking the approach to hydrocarbon monitoring in these processes can reduce risk and save you time and money.
Catalytic crackers have long been utilized to extract additional gasoline from heavier components resulting from the distillation process. The distillation process is the physical separation of a mixture of different molecules based upon the different boiling points of these molecules. The catalytic cracking process splits larger hydrocarbon molecules into lighter and higher value components such as gasoline by using a catalyst, which aids the reaction or “cracking” process. The cracking process produces carbon, or coke, which remains on the catalyst particle, reducing its effectiveness over time. Fluidized Catalytic Cracking Units (FCCU) will continuously route coked catalyst into a regenerator unit where oil remaining on the surface of the catalyst is stripped off with steam or solvent. The catalyst is then sent into the regenerator, where air is introduced to burn the coke off of the hot catalyst, usually in suspension. There are many different variations in the regeneration process: the semi-regenerative catalytic reformer and the continuous catalyst regeneration reformer (CCR). This last one is preferred because of the continuous regeneration of the catalyst, which allows plant operation for more than two years before a catalyst change is needed. This is important because the cost of the catalyst is very high.
One of the key parameters in the process is the purity of the nitrogen, which is required to move the catalyst from the reactor to the regenerator. The hydrogen content must be below 1% and total hydrocarbons must be below 15% in order to keep a non-explosive atmosphere in the process since high temperatures are needed. In addition, if hydrocarbons are burned they may lead to the formation of a coke lining over the catalyst, inhibiting its function, so monitoring is essential.
Challenges that arise in this application include the high quantities of dust due to the continuous flow of the catalyst that enables cracking. When older analyzers are used, it’s not uncommon for the dust to cause the sampling lines to plug, or even worse, damage the analyzer. This is often the result of a sampling system with inappropriate design for such a challenging environment. As a result, some plants use this as a reason to bypass the analyzer, and leave it without maintenance until it becomes useless. This is an extremely costly and dangerous approach, since the analyzer can signal a plant shut down, and if the signal is bypassed, the safety of the plant is threatened.
Also challenging is the fact that the area certification in these plants is classified as hazardous. This may drive users to install general purpose analyzers in high cost shelters that also require power supply, air conditioning, and safety devices. These shelters must be installed at floor level, representing larger tubing lines and the inherent time delay that affects the control of the application because the control system receives data with a delay of some minutes, and thus process safety is jeopardized.
Many analyzers currently installed on-site use analog outputs, and there is no way to know the status of the analyzer unless the tech is standing in front of it, which can be ill-advised in hazardous areas due to risks such as radioactive measurement of the flow rate of the catalyst moving bed, noise, height, and so on. New analyzers are able to send more information through a Modbus protocol to make the maintenance program of the analysis system easier.
A monitoring approach that can reduce risk and costs is to use an analyzer designed specifically for hazardous environments such as the X-STREAM Enhanced XEFD. Enclosed in a wall-mountable, flameproof housing certified for installation in CSA and ATEX hazardous areas, these modern analyzers offer communications protocols to keep the control room constantly informed of their condition as well as process feedback. The housing also means the analyzers do not require costly and space-intensive shelters, eliminating the need for additional utilities, such as power, air conditioning, etc. These systems offer the monitoring of both hydrogen and total hydrocarbons in a single analyzer, further reducing costs and time for installation, start up, maintenance and calibration. Because the systems are designed from the outset with very short sampling lines, which are far less likely to become plugged and have fewer fault points, analysis is faster and more reliable.
What kind of monitoring systems are you using in your catalytic regeneration processes? Have you experienced challenges?
By Dr. Michael Kamphus
To optimize plant performance and prevent expensive turbine damage, rapid control is critical for industrial power markets covering multiple energy sources. Maintaining turbine efficiency is an even higher priority today because of lower emission requirements and varying fuel sources due to the increase in unconventional natural gas sources, such as shale. Plant gas sources are primarily composed of methane, but typically there are extensive variations in higher hydrocarbons (C2+) as well. In fact, in some cases, over 18 percent variation has been recorded with fluctuations from 10 percent to 16 percent within one minute. Turbines have to be more flexible and need to present the above criteria over a wide range of loads because gas turbine power plants are often used only for peak loads.
Methane and higher hydrocarbons like ethane and propane behave differently during combustion. The variability of fuel sources can sometimes pose challenges for control and optimization, especially for combined cycle turbines with lower emissions. While a gas chromatograph can provide all the required measurements, the speed of response it provides is sometimes not sufficient for effective control.
The solution can often be a process gas analyzer (PGA) with a specific configuration of optical benches and filters that provide continuous measurement and the rapid response that’s required. In addition, an approximate calorific value (BTU) can be provided as long as the higher hydrocarbons are low in content. If this is not the case, the BTU value will be underestimated but never overestimated. Such values cannot be used for custody transfer but they may be adequate to prevent turbine damage and optimize performance. If the operator knows the variation of C2+ in the fuel sources, then that will substantially minimize the error.
With a 0–100 percent CH4 NDIR (non-dispersive infrared) bench measuring 7.85 μm, and a 0–25 percent C2H6 NDIR bench measuring 6.6 μm, an ideal solution has been designed that provides a high selectivity for CH4 against C2H6, C3H8 and C4H10 as well as CO2.
The C2H6 bench measures C2H6, C3H8 and C4H10 with response factors of 1.0, 1.0, 1.1 and gives a low response from CH4, internally corrected by cross compensation. The best accuracy is achieved in natural gas mixtures with CH4 as a major component, C2+ up to 20 percent, and low water content.
Combination with Other Measurements
Since CO2 content also varies in fuel sources, this measurement may be combined with the hydrocarbon values for better control and calorific value calculations. Carbon dioxide measurement utilizing optical NDIR technology can also be added to the configuration of today’s advanced process gas analyzers.
A calculation of the Wobbe Index is also possible utilizing a calculated relative density from the concentration values or by utilizing an external density signal. Calorific value calculations might require integration of additional channels. As with the BTU calculation, this is not for custody transfer but aids in rapid adjustments to operations, if fluctuations occur.
Methane (C1) and Ethane plus (C2+) measurements for natural gas power applications often take place in hazardous areas. Therefore a flameproof analyzer, such as the Rosemount Analytical X-STREAM Enhanced analyzer (to the right), is recommended.
The figure below shows a flow diagram of a typical analyzer system. Sample extraction, transport, and conditioning occurs using Rosemount Analytical Sample System Modules, which include a flanged sample probe, heated pressure reduction station, sample filtration, and sample flow control.
To prevent costly turbine damage or process shutdowns, it’s critical that plants conduct continuous measurement analysis with the rapid response necessary to monitor the component effectively. The Rosemount Analytical X-STREAM Enhanced multi-stream flameproof analyzer with optical benches and filters is ideally suited to help address these specific challenges to improve process performance.
To learn more about the Rosemount Analytical X-STREAM Enhanced analyzer and how it can help you improve your process performance, Click HERE.