Analytic Expert

Hi everyone. This is Doug Simmers talking again about improving your combustion processes.  The primary goal of combustion flue gas analysis is optimizing the fuel/air ratio, which minimizes fuel cost, lowers NOx emissions, and also minimizes the amount of carbon dioxide greenhouse gases emitted into the atmosphere. One overlooked use of flue gas analyzers is for balancing the combustion across large multi-burner furnaces.

Historically, a single flue gas analyzer placed downstream or in the smokestack was considered satisfactory for setting fuel/air ratios. Many furnace operators have moved the measurement location upstream, closer to the furnace, in order to get a faster speed of response, and added more analyzers for redundancy. This has proven to be a mixed blessing, since the analyzers almost never read the same O₂ levels, which lowers the operators’ confidence in the measurement, and subsequently their willingness to operate at the lowest possible O₂ setpoint. After many calibrations, it becomes clear that all the analyzers are all reading correctly, and the problem is that the combustion inside the furnace is unbalanced. When you think about it, this makes sense.

Four O₂ analyzers placed zone by zone at the top of the radiant section of a process heater furnace.

The combustion process is the burner. This is where the fuel and air are mixed and combusted. The furnace is mostly just a heat exchange envelope. If you have 50 burners in a large furnace, you have 50 discrete combustion processes, and some variability can be expected. This is the case for all large multi-burner furnaces, be they a 500 MW coal-fired boiler, a large crude process heater furnace in a refinery, or a steel reheat furnace.   Strategically placing an array of analyzers in the flue gas ductwork can help operators keep the furnace balanced, and prevent many problems.

Flue Gas Stratification Tells a Story
Forward-thinking operators will use these varying O₂ indications as a diagnostic tool to look for problems in the furnace, such as:

• Fuel Gas BTU variation – will be indicated by both O₂ and CO variation.
• Fouled burners – depending on the consistency and quality of fuel burned in a furnace, a burner will change over time.
• Flame carryover – combustion sometimes progresses well into and beyond the convective zone, and is indicated by lower O₂ readings, higher CO readings, or both, along with rising outlet temperatures.
• Tube leaks – an unbalanced furnace can cause flame impingement and associated tube wastage.
• Furnace casing leaks – will result in elevated O₂ readings, since 21% of the air leaking in is oxygen.
• Sticking dampers – stack outlet dampers are sometimes poorly maintained, and sluggish control of O₂, COe, and furnace draft are indicative of problems.

Combustion flue gas analyzers have become true analytical tools for determination of all kinds of furnace problems. We’ll talk about others in future blogs.

For more information on this subject, please visit the following links:

• Flue Gas Analysis as a Diagnostic Tool for Fired Process Heater Furnaces Application Note
• Flue Gas Analysis as a Furnace Diagnostic Tool PowerPoint
• Flue Gas Analysis as a Furnace Diagnostic Tool ISA paper
  

Measuring pH in liquids with many dissolved solids is a constant challenge for all types of industrial plants. For Kyokuto Petroleum Industries (KPI) Japan, continuous failure of their pH measurement in their desulfurization scrubber was costing significant time and money.

The KPI scrubber is a magnesium hydroxide system. The pH measurement is installed after neutralization and the wastewater includes many magnesium sulfate solids. The flow chamber was sometimes clogged with solids.

KPI had been using a pH sensor with a water jet cleaning system. The cleaning system, however, was ineffective against solids that coated and plugged the glass and liquid junction of the sensor. After a few days of operation KPI could no longer trust the pH values being received as the readings would fluctuate significantly. Even when the sensor was cleaned manually, a time-consuming and expensive process, the pH sensor had to be replaced every month.

As a result, KPI often had to control the dosing of magnesium hydroxide manually based upon the experience and intuition of the operators. In addition to the cost, personnel time and extreme inconvenience, the plant was faced with significant local regulations regarding emission of SOx. If the manual control led to low magnesium oxide dosing, a SOx emission could occur with subsequent fines. If the dosing was too high, the costs of the expensive magnesium hydroxide soared and increased costs.

On top of all this, the pH sensor KPI had been using was connected to an analog device which made it impossible to get sensor status from the instrument automatically. The company could not predict sensor failure or receive other data without manual intervention.

With good reason, KPI was looking for a method of applying automatic control to its set points based on reliable pH measurement.

KPI switched their pH analysis to the Rosemount Analytical Model 1056 using the PERpH-X 3300HT-10-30 with SMART pre-amp as a sensor. The PERpH-X sensors are designed with an enhanced double junction reference that is specific to extreme applications. Reference flow into the process stream is controlled using a porous Teflon® junction that can be replaced in the event of fouling or plugging. The specially designed junction is chemically resistant and has a large surface area to maintain a steady reference signal in dirty or oily applications. This reference also resists poisoning which can occur with other sensors as a result of the diluted hydrochloric acid used to manually clean the sensor during preventive maintenance.

The 3300 has been able to operate accurately for two to three weeks before manual cleaning and the sensors are able to be used more than nine months in the process as KPI also takes advantage of the rebuildable reference feature of the 3300. The 3300 has lasted nine times longer than the previously used sensor – a dramatic improvement saving time and money.

The HART-enabled pH measurement by the 3300 allows KPI to monitor other valuable information such as reference impedance, glass impedance, temperature, etc. By monitoring these sensor parameters, KPI could detect a sudden large deposit of the reference impedance. Figure 1 shows the increasing reference impedance trend as well as the result of a sudden deposit. This information is used by KPI to improve the timing of maintenance. They are also able to use temperature data to determine clogging of the flow chamber which saves both maintenance costs and prevents shutdowns. Using the Emerson 1056P-HT with a 3300HT sensor with the SMART pre-amp and jet sprayer, KPI has been able to control the dosing volume of magnesium hydroxide automatically saving time and improving efficiency. While savings in actual product costs measures in the thousands of dollars, the value of the accurate measurement is incalculable.

The call comes in on a regular basis … “My process conductivity does not match the lab … help!”

Usually this is followed by a conversation about the instrumentation not working. However, rarely is the instrumentation at fault. After checking temperature calibration, slope and offset, and cell constant settings the instrumentation is shown to be operable and fully functional. The problem: using commercially available standard solutions is not a good method of calibrating conductivity below 100 µS/cm.

There are a number of reasons that this method is prone to failure: instability and inaccuracy of the standards, temperature variation, and instability of samples themselves. The article “Is There an Accurate Low-Conductivity Standard Solution?” goes into great detail about the accuracy of the method typically employed for calibrating conductivity – a method that is sorely inadequate for low level measurements. However, there is a solution which is also explained in this article.

The solution incorporates the Model CVU Conductivity Validation Unit designed by Rosemount Analytical to meet the critical calibration needs of the life science industry. The same solution lends itself to resolving discrepancies between labs and process in power, chemical and refining and a host of other industries that utilize low conductivity water for boilers, steam generation and process feed.

What is your experience with conductivity measurement?

Hello, this is Mauricio Romero, Latin American Business Development Manager for Emerson Process Management, Net Safety. In this blog post I’m going to outline challenges related to flame and gas detection within Geothermal power plants. Geothermal energy is a nonconventional supply which has many advantages. It is completely renewable, requiring only naturally present water and is continually replenished by heat generated from the earth’s core. There are very few, if any, by-products from the resulting steam, so the process is very clean and is of course a completely domestic energy source. With the cost and efficiencies associated with geothermal energy production beginning to match that of traditional power sources, more utilities and other companies are finding ways to take advantage of this resource.

Perhaps one of its few limitations is that the steam generated in many cases cannot be used as the primary driver for turbines, because it is not hot enough to flash on its own and water droplets can cause serious damage to mechanical components of the turbine. One good way to resolve this is by using a binary cycle concept design that uses hot water from the geothermal sources and a fluid with a much lower boiling point than water that is heated by the geothermal source – the steam from this liquid is then used to drive the turbine.

One of the best options for this application is pentane, which has a much lower boiling point than water. One huge disadvantage is that it’s extremely explosive, and even more so when converted into an absolute gaseous state.

In order to create a safe environment a reliable detection solution must be put in place to monitor the plant area for any potential pentane gas leak that can develop into an very serious condition if ignition was to take place. Normally these plants are located in remote areas, so detection technology must be very robust with minimum maintenance requirements, and power consumption has to be well monitored in order to avoid wasting the valuable energy generated onsite.

Installing Emerson Process Management, Net Safety detection solutions has proven to be an effective way to monitor potential hazards in this type of installation. Either catalytic bead sensor or infrared sensor technology can be used to monitor gas leaks of hot pentane, which happens to be a very heavy gas, making it extremely dangerous. Some alarms can be configured to provide early warning of dangerous concentrations of pentane in the environment, which can be used to alert personnel by means of signaling devices such as strobes or horns. This early detection will allow plant operators to proceed with effective measures that can range from isolating the environment, inspecting the area to visualizing points of pentane leakage. If a gas release results in a fire, optical flame detectors such as UV/IR or IR3 technology will be ready to respond instantly. Fast and accurate notification from flame detectors will also allow personnel to proceed with effective emergency response, potentially from remote locations, so time is of the essence in these circumstances. It may involve releasing of extinguishing systems to protect property, partial or total shutdown of the plant to minimize consequences, and evacuation of any personnel in the facility.

Net Safety detection technologies have proven to be an optimum solution overall in this application, due to a combination of highly robust construction that can resist the most challenging plant conditions and extreme environments, the lowest possible power consumption for fixed detection devices, with intuitive designs and special features that make Net Safety instruments highly reliable, user friendly and low maintenance.

Hi everyone. This is Shane Hale, natural gas product marketing manager. I recently wrote an article for Pipeline & Gas Journal about using gas chromatographs to determine hydrocarbon dew point. The determination of hydrocarbon dew point (HCDP), the temperature at a defined pressure at which hydrocarbon liquids begin to form, has become critical for the natural gas industry. A big reason is that producers are focusing on extracting heavier gases in traditional and shale plays in an effort to produce more profitable natural gas liquids (NGLs) rather than the natural gas that is selling at historical lows. This has increased the risk of hydrocarbon liquids entering or forming in gas transmission networks if this rich gas is not processed fully.

The traditional method of determining the hydrocarbon dew point online is to use a chilled-mirror device that reduces the temperature of a mirror in a measurement chamber filled with the natural gas until enough hydrocarbon mist condenses on the mirror to be detected. Other dedicated HCDP analyzers using different measurement techniques are also available; however, they all provide a HCDP only at a single pressure and are dedicated analyzers that provide a single measurement.

An alternative to a dedicated HCDP analyzer is using an equation of state (EOS) to calculate the hydrocarbon dew point at any pressure from the composition obtained from a gas chromatograph (GC). By entering the composition of the natural gas into a recognized equation of state, the theoretical HCDP can be calculated for any pressure as well as the cricondentherm (the highest dew point temperature at any pressure). The validity of the calculated value depends on the accuracy of the composition used especially for the higher carbon number hydrocarbons (C6 to C9).

Gas chromatographs are already used in custody transfer measurement to determine the energy content, compressibility, density, and other physical properties. Therefore, using a gas chromatograph to determine the HCDP using an EOS provides additional valuable information from already required equipment.

To learn how the C9+ gas chromatograph can be used to calculate hydrocarbon dew point at any pressure allowing pipeline operators to take corrective action before heavy hydrocarbons enter the network, click HERE. And let us know if you’re using, or have considered using a gas chromatograph at your plant!

Hi everyone. I’m Rich Baril, product marketing manager at Emerson Process Management. All of us at Rosemount Analytical get very excited about water. Maintaining and improving water quality for municipal, industrial and commercial applications is one of our biggest jobs. Today, I want to talk about a technology being used more and more to maintain drinking water quality – whether at the treatment plant or bottling plant – and that’s ozone.

As you know, many different pathogens (bacteria, viruses and parasitic protozoa), some of which are potentially lethal, can be found in both surface water and some groundwater sources. Disinfection is integral to ensuring water quality and safety. Large-scale use of chlorine for water disinfection began in the U.S. in 1908, and chlorine is now used in both primary and secondary disinfection steps at many water treatment plants. However it has been reported that trihalomethanes and haloacetic acids are produced as byproducts of the chlorination process, and that these byproducts could be hazardous. Ozone also can produce byproducts, bromates, and much study about safe levels is being conducted.

In response to these reports, many water utilities have begun examining alternatives to chlorine for primary water disinfection, two of which are monochloramine and ozone. We will discuss ozone in this blog.

The first drinking water plant began operations in Nice, France in 1906. Since Nice has been using ozone since that time, it generally is referred to as the birthplace of ozonation for drinking water treatment. Today, some U.S. water plants are moving to ozone for disinfection to address more stringent drinking water regulations. Ozone is a powerful oxidant. Its effectiveness is measured by the amount of residual ozone remaining. The presence of a small residual implies that all organic compounds have already been neutralized.

Adding ozone to bottled water is a way to ensure that the water in the bottle is free of microorganisms, without leaving trace disinfectants.  When diffused into water, ozone oxidizes organic material, including waterborne microorganisms. It’s more effective than chemical disinfectants like chlorine and is both odorless and tasteless.  Because of ozone’s short half-life, any bottled ozonated water will have little or no remaining ozone in the solution.  It will have received an effective disinfection prior to bottling which will leave no residual disinfectant.

Ozone gas is produced by electrical discharge in air. The gas is injected into a contact chamber via diffusers to distribute the gas evenly and speed the disinfection process along. The ozone concentration in the contact chamber, where reaction is still occurring, can therefore be much higher than in the final effluent. Some ozone generator manufacturers recommend monitoring ozone concentration in the contact chamber to meet disinfection requirements. Aside from the capital cost of the ozone generator itself, the main cost of an ozone system is the electricity used.

Have you used or considered using ozone for water treatment? What was your experience? We’ll be happy to talk with you about the effective use of ozone in your water treatment or bottling plant – just let us know!

Ensuring safety for personnel and protection of facilities and equipment is a top priority for all industrial plants. A critical element of this is the effective detection of dangerous flammable and toxic gases and vapors and their potential ignition. However, building an effective safety monitoring solution is a complex task as there is no single system or technology that would be the solution for every plant. There are several fundamental choices available in detection technologies. Jonathan Saint from Emerson Process Management, Net Safety recently published an article with Facility Safety Management that addressed the available options and how to build a solution that works for your plant while saving lives, property and dollars.

An effective solution requires three levels of detection. Safety systems that deploy a diverse range of safety technologies can counteract the serious impacts of gas leaks and the potential for fire and explosions. The article entitled Three Levels of Detection Safety Monitoring: Combining Technologies for Reliable Results addresses the different types of gas and flame detectors, including point type, line of sight, ultrasonic and flame detectors, and their strengths and weaknesses and how to build an optimal solution using an effective combination of these. Read the full article HERE. Following is an excerpt:

Safety systems that deploy a diverse range of detection technologies can counteract the serious impacts of gas leaks and potential for fire and explosions. A combination of ultrasonic leak detectors, fixed gas monitors and flame detectors, is particularly effective because they’re complementary and cover the three detection defense levels.

The first stage is the immediate leak stage, which has the greatest opportunity for fast and effective mitigation; the second is during the gas cloud formation or accumulation stage, which is a very serious safety condition; and the third is during the ignition state, which can be catastrophic.

Ultrasonic detectors are often installed outdoors to cover wide areas with challenging detection conditions. Point detectors should be installed at or near known high-risk gas leakage points or accumulation areas to provide information on the level of gas present in these areas. Open-path gas detection systems are more effective at plant or process area boundaries. They monitor the plant perimeter and provide an indication of overall gas cloud movement in and out of the facility.

The movement of gas clouds throughout the facility is tracked by monitoring the output signals of all the gas detectors within the safety system. Optical flame detectors monitor wide areas for IR or UV energy related to the ignition of a gas source and provide instant alarm condition back to notification and mitigation systems.

A variety of challenging factors affect the performance of these technologies; location (indoors/outdoors); air flow; gas properties (type, density, buoyancy); environmental conditions like temperature and humidity; background conditions (false alarm sources); and obstruction. Best practices for each application will be different, but it’s critical to perform proper HAZOP analysis and identify the sequence of events leading up to an accident.

Every safety engineer that is committed to safeguarding personnel, plant and productivity, and employing a system that provide comprehensive, tiered coverage can yield optimal results before an escalated incident occurs.

To read the full article, click HERE.

Are you providing the optimal safety coverage within your applications?

Hi, my name is Shane Hale, Product Marketing Manager for Natural Gas at Rosemount Analytical, and today I’d like to discuss a gas chromatograph application for the amine systems in natural gas processing that you may not be familiar with, but can dramatically reduce foaming events and increase production rates.

In natural gas processing, amine systems are frequently used to remove CO₂ and H₂S from rich gas streams. When hydrocarbon liquids are introduced into the amine contactor, however, foaming can occur which significantly reduces the efficiency of the acid gas extraction.  This happens because, when hydrocarbon liquids enter the contactor, they are highly soluble into the amine solution and reduce the surface tension of the aqueous solution. The reduced surface tension then aids in creating bubbles of gas in the amine solution, resulting in foaming. At that point, operators need to reduce flow and may even have to inject foaming inhibitors into the system to regain control.

Avoiding foaming is difficult. The efficiency of amine systems to remove H₂S generally increases with lower operating temperatures, and the efficiency at removing carbon dioxide occurs at a specific temperature. However, lower temperatures in the contactor also increase the potential for liquid hydrocarbons to form in the inlet stream and thus increase the potential for foaming to occur.

C9+ Gas Chromatography

Figure 1 – Calculating the Hydrocarbon Dew Point of the inlet stream at the contactor pressure provides an early warning for liquid hydrocarbons in the inlet stream and defines a minimum temperature for the lean amine inlet stream to avoid amine foaming from liquid hydrocarbons.

The solution to the problem is hydrocarbon dewpoint (HCDP) and this is where gas chromatography comes into play. Determining the HCDP of the inlet gas provides the opportunity to (1) avoid hydrocarbon liquids entering the contactor and (2) control the amine temperature to a set-point that optimizes the efficiency of the acid gas extraction while also avoiding the risk of liquid hydrocarbons forming in the contactor. The theoretical HCDP of a gas mixture can be calculated from the gas composition using an equation of state. Typical gas chromatographs used in natural gas applications measure individual hydrocarbons up to n-pentane, and combine all the heavier components as a C6+ value. However, the components that drop out as liquids and cause the foaming issues are the components heavier than C6, so calculating the HCDP with a C6+ analysis (using assumed ratios of C6/C7/C8) will provide inaccurate results that will not be suitable for use in a control strategy. A C9+ gas chromatograph measures the ratio of C6, C7 and C8 components (with heavier components reported as C9+) and provides a much more accurate HCDP calculation that can then be used to optimize the control strategy.

Figure 2 – The process pressure is used to calculate the HCDP at process conditions that provides a two-phase flow early warning for use in the control strategy to avoid foaming in the contactor.

Determining the Phase of the Inlet Gas
When the inlet gas temperature is below the HCDP, the flowing stream is a single phase vapor. As the gas becomes richer with heavy hydrocarbons, the calculated HCDP will approach the stream temperature. When the HCDP reaches the stream temperature, the heavier components will begin to drop out into the liquid phase, increasing the risk of foaming in the amine contactor. By calculating the HCDP at the line pressure with the C9+ gas chromatograph, the difference between the stream temperature and the HCDP can be monitored. As the HCDP approaches the stream temperature an alert can be triggered that enables the operator, or the control strategy, to take actions to reduce the HCDP before liquids form and enter the amine contactor.

Using HCDP for Amine Inlet Temperature Control
The temperature of the amine contactor is typically controlled by cooling the lean amine prior to entry into the contactor to maximize the efficiency of the acid gas removal. However, if the temperature of the contactor is below the HCDP of the inlet gas at the contactor pressure, then liquid hydrocarbons will begin to form as the inlet gas enters the contactor and the risk of amine foaming greatly increases.

As the HCDP varies with pressure, the HCDP of the inlet gas will change as it enters the contactor. By calculating the HCDP of the inlet gas at the pressure of the amine contactor, the minimum temperature of the inlet amine can be determined and used in the control strategy to minimize the risk of amine foaming.

If the determined minimum temperature is too high for the efficient acid gas removal, actions can be taken to reduce the HCDP of the inlet gas while also avoiding the risk of amine foaming.

Emerson has led the industry in the development of gas chromatography for C9+ applications and customized solutions using the 700XA Gas Chromatograph by Rosemount Analytical.

Are you struggling with Amine Foaming in your plant? If so, we’d like to hear from you…

Click on the following links to find additional resources for this blog:

• Avoiding Amine Foaming Application Note
• Hydrocarbon Dew Point (HCDP) Application Note

Monitoring pH is critical in virtually every manufacturing plant, regardless of industry or process, but maintaining effective pH measurement can be challenging and complex. Problems with pH sensors can range from difficulties with field calibration to cracked glass to reference clogging, and these issues can result in expensive maintenance requirements or even process downtime.

The current issue of Plant Engineering features an article by our own Linda Meyers, senior product manager, Emerson Process Management, Rosemount Analytical, on new smart technologies for pH sensors that can communicate the health and status of sensors to control systems, reducing costs and preventing downtime.

Below is an excerpt from the piece, and you can CLICK here to read the entire article.

Ask plant operators about their most time-consuming and burdensome tasks, and chances are they will mention the field calibration of pH sensors. In addition, pH sensors are often isolated from the central plant information systems, which makes them maintenance nightmares and creates potential risks of downtime.

Fortunately, while pH technology is classic, the continuous improvements to pH systems are helping to overcome some of these operational problems for plant engineers. One of these improvements is making pH sensors “smart” — smart enough to hold calibration and other data and to communicate that information to central control systems. The result is lower cost of operation, substantially reduced maintenance requirements, and reduced downtime in a wide range of applications.

The calibration nightmare
Traditionally, the only way to calibrate a pH sensor was to carry all of the calibration equipment into the field. New technologies now embed memory in pH sensors, which allows them to hold calibration information. This means a sensor can be calibrated in a controlled environment such as a lab or maintenance shop. The information is then held in the sensor memory as the sensor is taken into the field and installed. Pre-calibrated sensors can even be stored on shelves and then taken into the field to replace a sensor requiring calibration or maintenance. No more bottles and beakers in the snow, plus no downtime.

Smart diagnostics
Because the new sensor technologies store data in the sensor, they also solve another important pH measurement problem — unpredictable failure.

The information stored in the sensor that can be used to predict accuracy and sensor life include:

• Slope trends, which normally decrease over time
• Glass impedance trends, which normally increase over time
• Reference offset trends, which normally shift slowly over time
• Reference impedance trends, which normally shift slowly over time.

Read the full article by CLICKING here.

For more information on Rosemount Analytical SMART pH technology, CLICK here.

And CLICK here for a video on SMART pH Sensors and Instruments for Plug and Play Use.

Hello, I’m Michael Kamphus, application engineer for Process Gas Analyzers at Emerson Process Management, and today’s topic is the measurement of harmful gases that impact climate change and the technology used to control these.

As seen in the latest IPCC (Intergovernmental Panel on Climate Change) reports, CO₂, CH₄ and N₂O gases have the biggest effect on global warming. In addition to the previous, the EPA (US Environmental Protection Agency) also lists HFCs, PFCs, Halocarbons and SF₆ gases as major contributors to air pollution and global warming. Today, international agencies and governments are enforcing stronger emission regulations of these gases and willing to issue strict penalties and steep fines to those who do not comply. Technological advancements in today’s process gas analyzers have allowed gas processing plants, refineries, and others alike to safely measure, analyze, and closely monitor greenhouse gases in order to adhere to emission standards and protect the environment.

Rosemount Analytical, a business unit of Emerson Process Management, continues to lead the way in providing refineries, plants, and gas processing centers with the expertise and technology to accurately measure these greenhouse gases and remain compliant with today’s emissions standards.

The following are two examples of successful installations of Rosemount Analytical process gas analyzers monitoring greenhouse gas emissions:

Most of the industrial N₂O emissions come from nitric acid plants, many of which produce fertilizer. After oxidation of NH₃ to NO, NO reacts with water to form nitric acid, N₂O is a byproduct of the oxidation reaction. Special catalytic reactors can be implemented to eliminate the N₂O gases from nitric acid plant emissions. Measurement of flow and N₂O concentration behind the reactors are regulated by UNFCC (United Nations Framework Convention on Climate Change) within CDM (Clean Development Mechanism) projects. Both measurements need to be performed with QAL1 certified equipment. QAL1 is part of the European Continuous Emission Monitoring regulation. Rosemount Analytical N₂O gas analyzers now have a new QAL1 certification providing exceptional accuracy helping to earn carbon credits from N₂O emission reduction. Currently there are installations all over the world including Egypt, South Korea, South Africa and Chile. Recently, a major global engineering company partnered with Emerson Process Management to help control an N₂O abatement reactor and provide a complete turnkey solution which includes the installation and startup of temperature transmitters, pressure transmitters, flow transmitters, valves, gas analyzers and DCS systems to provide plant control and data reporting.

Other successful installations are in Australia, where the government has introduced carbon tax for emissions of greenhouse gases from coal mines. Therefore CO₂ and CH₄ have to be measured. A coal mine can pay up to $10M in carbon tax and a high-accuracy analyzer can help to reduce tax payment uncertainty. Rosemount Analytical worked with an Australian OEM company to successfully install high-accuracy process gas analyzers in flame-proofed housings for two separate applications: the first – to measure CH₄, O₂, CO and CO₂ in the tube bundle system for underground ventilation control and safety monitoring; the second, measure CH₄ and CO₂ from the exhaust of underground coal mines.

What kinds of harmful gases does your plant need to measure? What challenges do you face in that measurement?