Combustion, Gas and Liquid Analysis, Flame & Gas Detection - Recent Threads

GC 370 XA can't start and there is information on the screen "Rebooting system due no found to connected database"

Hadi Familiyanto — Thu, 24 Apr 2025 07:26:25 GMT

Dear Sir

We would like to ask about the GC 370 XA not working and the screen says Rebooting system due to no found to connected database, what is the problem with this GC?

Please help and support solving this problem

Repeatibility and Linearity in 5081-A Transmitter

farzan — Tue, 18 Jul 2023 22:42:10 GMT

I want to use 5081-A Transmitter along with 499ATrDO Dissolved oxygen sensor.

Our required calibrated range is 0-20 ppb.

In the transmitter 5081 datasheet (LIQ_PDS_5081/Rev.R Page#6) under the heading of General Specifications for 5081-A, it is defined as following:

Repeatibility (Input) = 0.1% of range

Linearity (input)= 0.3% of range

and above some input ranges are given in current units.

Now, we know that the sensor 499ATrDO has the range of 0.1 to 20 ppm (i.e. 20,000 ppb), so does it meant that the repeatability of the transmitter will be 0.1% of 20,000 ppb? and similarly linearity will be 0.3% of 20,000 ppb? This will result in a very high values for repeatability and linearity as our working range is only 20 ppb. Can you please explain this doubt?

Regards

Use of Flame Simulator Model: FS-IR-975 and FS-HR-975

Rodrigo Sandoval — Tue, 29 Nov 2022 18:46:08 GMT

Dear Experts

Flame Detector 975MR has a range of 4μm and 5μm to detect hydrocarbon-based fuel and gas fires

Flame Detector 975HR has a range of 2μm and 5μm to detect hydrogen fires

In order to have in stock just one flame simulator I want to acquire the Flame simulator model FS-HR-975 where according with the spectrum range is able to simulate Methane and Hydrogen spectrum.

I wonder if it's possible with one flame simulator FS-HR-975 carry out both scenarios?

I look forward to your advice and comments

Best regards

Rosemount™︎ 3300HTVP PERpH-X™︎ High Performance pH and ORP Sensor

Ahamed farid — Tue, 02 Nov 2021 08:43:22 GMT

Dears,

We use 3300HTVP pH to neutralize inclinator waste acidic liquids. Sensor is mounted directly to the process. There is no option for effluent disposal. The sensor is get damaged very frequently typically one or two weeks. I doubt some small particulates damaging the glass electrode. Operation maintain high flow for mixing chemicals. They are expecting pH reading with no lag. Kindly give a solution.

Kind Regards

Daniel Senior Fitting with Profiler plate

brian remley — Sun, 03 Oct 2021 23:36:00 GMT

Anyone has noise issues at flow rates coming from the conditioning plate or orifice fitting?

P/N clarification for PCA MAIN CPU for 700XA GC

Otabek N. Fayzullaev — Thu, 03 Jun 2021 12:19:38 GMT

Dear Sir,

Pls. confirm the part number interchangeability of PCA MAIN CPU for 700XA GC: "2-3-0710-007" vs. "7A00555G02".

Best regards,

Otabek N. Fayzullaev

Gas chromatography daniel 500

Mohammed .M — Fri, 23 Apr 2021 10:21:23 GMT

as chromatography

Dear all
we had issue regarding the Daniel® Danalyzer Model 500. Gas Chromatograph. failure C6 hexan,C2 please note the below.

Observed While we are facing issue with GC 500 (Error and Range out of limit in and deviation RF alarm Hexane, Ethane , Propane is showing Zero). What the step to solve this Issue

So kindly support to fix this issue .

Converting Emerson 700XA Gas Chromatograph Status Signals to Modbus Holding Registers

Shaiq Bashir — Mon, 08 Feb 2021 17:06:26 GMT

Dear Emerson Support

We have one 700XA Gas Chromatograph on which some of the boolean status are configured on Modbus Coil addressss (10000-19999). Some of the boolean status are as following:

No Sample Flow

Analyzer Failure

Low Carrier Pressure.

The flow computer that we have interfaced with this chromatograph supports only Holding Registers (40000-49999). Is it possible to change such status signals in Gas Chromatograph modbus map to Holding Registers?

gas chromatography

Mohammed .M — Fri, 27 Nov 2020 16:15:41 GMT

Dear all
we had issue regarding the Daniel® Danalyzer™ Model 500. Gas Chromatograph. failure C6 hexan, please note the below.

Observed GC Hexane issue showing 0 value. While troubleshooting when it is calibrating from calibration gas Hexane value coming exactly 0.2 % alarm not coming. When it is keeping through Sample line Hexane value going to zero value again alarm giving in DCS and SVR also Hexane low value. Remaining all gas composition are coming exactly.

So could you please advise form emrson or roemont

Flame & Gas Detection Application Spotlight: LNG Terminal Tank Storage

Amanda Rahn — Fri, 08 May 2020 18:46:23 GMT

Liquefied and compressed natural gas commonly used for distribution into the consumer market is often stored at facilities in pressurized bullet tanks. At these sites there are often multiple bullet tanks arranged in a row with uniform valve and fitting placement – all of which are potential leak points.

Open path gas detectors are used for terminal site tank farm storage and for fence line, perimeter, and large area monitoring. These devices provide high-speed and accurate response for large scale combustible gas leaks which might occur along a clear line-of-sight up to 660 feet (200 meters) in distance.

Watch this quick video to learn more >

Flame & Gas Detection Application Spotlight: LNG/CNG Loading Racks

Amanda Rahn — Fri, 01 May 2020 15:39:28 GMT

Liquefied natural gas and compressed natural gas loading racks are used for the transfer of pressurized gases between storage tanks and various transportation mediums including truck, train, or marine vessels. Protection of these facilities is critical due to the large inventory of flammable substances on-site. Acoustic gas leak and flame detection technologies could improve safety at these facilities by quickly and accurately detecting the presence of hazardous material releases.

Watch this video to see how Flame & Gas Detection devices can help increase safety at loading racks.

Flame & Gas Detection Application Spotlight: Gas Turbine Power Generation

Amanda Rahn — Tue, 28 Apr 2020 13:59:13 GMT

Gas power turbines use compressed natural gas as a fuel source to generate electricity - additionally other lubricants are present in the operation of the turbine to provide cooling and to prevent engine wear.

Common fire and gas detection related challenges faced at these sites have to do with high heat and vibration levels. For instance, gas sensors inserted into gas turbine enclosures are subject to high heat and may lose sensitivity and response speed over time. Additionally, flame detectors placed in these enclosures may experience high vibration and heat leading to shorter service lives.

So how can you be reassured that your flame and gas detection system is working as effectively as possible at gas turbine applications? Watch this video to learn dependable solutions to these common problems >

Flame & Gas Detection Application Spotlight: Compressor Stations

Amanda Rahn — Fri, 24 Apr 2020 16:38:04 GMT

Compressor stations often include dual fuel turbines using various combinations of natural gas, hydrogen, and diesel as a fuel source. In addition, lubricants are present in the operation of the turbine to provide cooling and to prevent engine wear.

A common safety challenge faced at compressor stations includes when pressurized leaks at critical junctions create atomized fuel or lube oil in the intake or exhaust manifold leading to the risk of combustion when contacting hot operating surfaces within the enclosure. An additional challenge has to do with leaks of pressurized hydrogen or natural gas that could occur at multiple locations and across several compressors within the facility creating an unsafe environment that could lead to an explosion

Do you know which Flame & Gas Detection devices would help address the above concerns to benefit the safety level of your compressor station site? Watch this brief educational video to find out.

infrared Hydrocarbon

Mohammed .M — Tue, 14 Apr 2020 05:45:58 GMT

Netsafety MILLENNIUM II Infrared Hydrocarbon

Dear all

Good Day

We are the customers of Netsafety MILLENNIUM II Infrared Hydrocarbon Model No: M21-A-S.It has been observed Gas Sensor of all transmitter not working in field.

And we have been communicated with the factory and the supplier regarding the part (cartridge) and reported not to sell a product to via Emerson and informed us that the shelf life is more than five years note

that we have many cases of failure on the device. As per the manual Warranty its 5 years and the life work 7-9 year .Please inform you about this and your comment is very important to us as customers .

Netsafety MILLENNIUM II Infrared Hydrocarbon

Make : DYNAMENT

Model No. : MSH-HC/NC/M

So could you please advise

Regards

Insidious Corrosion of Fixed Equipment Detected Via Predictive Maintenance

Jake Davies — Tue, 24 Mar 2020 17:57:26 GMT

When walking through your plant, do you ever look at the piping and wonder if it is still sound and strong, or so corroded internally that it could burst at any moment?

Hopefully such a question isn’t entirely uninformed. You should have some sense of the condition of vessels and piping and whether they are nearing the end of their practical service life. The question is how accurate that sense really is.

Getting a better handle on stationary equipment condition is the topic of my article in the February 2020 issue of Oil & Gas Engineering, Insidious Corrosion of Fixed Equipment Detected Via Predictive Maintenance. It makes the point that many plants do not give the attention they should to these kinds of plant assets.

Discussions of predictive maintenance in the oil & gas industry usually focus on rotating equipment such as pumps and turbines. Those are certainly valid areas of concern, but the result of a failure is usually limited to the equipment itself. On the other hand, static equipment such as piping, vessels and similar equipment is not as maintenance intensive, but a failure can be catastrophic. This equipment should also receive predictive maintenance attention.

Most plants try to implement such a practice by using portable ultrasonic wall thickness measuring devices to check piping. This is fine as far as it goes, but it is difficult if not impossible to get consistent readings over multiple years. There are simply too many variables in play between the equipment and people using it, and in any case the results are reported periodically, and not continuously. One refinery reliability team willing to show us its data had to admit that it was statistically meaningless. Measurements taken by hand, in supposedly the same spots over 20+ years, were all over the place.

Predicting damage rates is challenging, especially in areas where the corrosivity or erosivity of the process fluid varies frequently. Nowhere in the production chain is this experienced more than refineries, which therefore have the highest variability in corrosion and erosion load. Traditional inspection methods just discussed simply don’t provide adequate quality or sufficient measurement frequency to drive predictive maintenance able to keep equipment running safely.

The answer is using permanently mounted thickness probes which measure continuously, drawn from Emerson’s Rosemount Wireless Permasense Corrosion and Erosion Monitoring System product family. This effort can be organized and managed using Emerson Connected Services for Corrosion and Erosion Monitoring, which brings together all the data collection and analysis to guide maintenance efforts.

So, as you think about your situation, do some digging into your own efforts so far:

Are there records of thickness measurements taken over the years?
Is this thickness measurement effort well organized and practiced routinely?
Do specific thickness reading locations indicate consistent metal thinning over time?
Are there plans to systematically replace piping and vessels based on this predictive measurement?
Is the injection of corrosion inhibitors to process media closely controlled based on pipe wall thickness measurements?

If you’re answering “no” to one or more of these questions, it’s time to consider what you might need to do before there is a catastrophe. Measuring wall thickness using permanently-mounted, ultrasonic wireless sensors provides highly useful data for maintenance programs, as discussed in greater detail in the article.

Let’s hear about your situation. How did you answer the questions just asked? Have you been successful with periodic manual measurements, or has it been haphazard?

Optimal Gas Analysis Decisions Improve Ethylene Plant Operation

Dave McMillen — Wed, 11 Mar 2020 16:46:59 GMT

One astonishing statistic regarding the oil and petrochemical industry is that 200 million tons of ethylene will be produced this year, much with 99.99% purity. This high level of performance is possible thanks to analyzers helping control the process and verifying the result.

Creating this much product with such a high level of purity depends on more than 30 gas analysis measurement points in a full ethylene production unit, from feedstock to delivery of multiple product and byproduct streams. Installing and maintaining these analyzers can be challenging, but answers are at hand.

Gas analyzers are arguably the most complex and often misunderstood instruments in a chemical plant. There are many technologies with different capabilities, which can cause confusion as to which is best for what purpose. Michael Kamphus and I tried to help clear this up in our article in the January 2020 issue of Hydrocarbon Processing, Optimal Gas Analysis Decisions Improve Ethylene Plant Operation. Much hinges on the demand for high purity.

These stringent purity requirements must be verified in production and at custody transfer points because the presence of impurities can poison catalysts and affect downstream processes, leading to costly repairs and downtime. Stringent environmental requirements relating to gas emissions also exist. Since purity is essential, the precision and reliability of the measurement is of key importance. Speed of response to any potential issues—along with cost reduction—are also critical to prevent potential process upsets and to ensure optimum throughput.

There’s no question this reality puts enormous pressure on effective analyzers, which means selecting the right types and using them in the right process points. The question quickly emerges, how do you make the right selections? That’s a tough thing to answer in one article, but we did our best to review the different gas analysis measurement points in the process and offer suggestions for specific gas analyzer technologies based on how each is designed to better perform at various points in the process. We started by defining three general technology categories:

The measurement of purity and process optimization in ethylene plants is accomplished by gas analysis systems, principally gas chromatographs (GCs), laser spectroscopy analysis systems, and conventional continuous gas analyzers. The latter use a variety of measurement technologies such as photometric nondispersive infrared (NDIR) and nondispersive ultraviolet (NDUV), thermal conductivity, paramagnetic and electrochemical oxygen. While virtually every ethylene plant uses some combination of these technologies, not all use them optimally. Applying the right specific gas analysis system in each process and unit will help companies thrive in the competitive petrochemical industry.

Using a gas analyzer optimally depends on the type of measurement needed, the gas being measured or the relative concentration to be sensed. Gas analysis measurements at an ethylene plant have traditionally been predominantly made by infrared and gas chromatograph analysis techniques, supported by techniques for emissions analysis. However, recent advances in tunable diode laser and quantum cascade laser spectroscopy have expanded the measurement technologies available for faster and more accurate control of the process at certain points.

If you are struggling with consistency in meeting purity requirements, complying with emissions levels, controlling production costs, or having access to real-time process analytics, it is critical to assess the performance of each gas analyzer technology.

Tell us about your situation and how you have applied gas analysis technologies. You can share with others about your implementations and experiences at the Emerson Exchange365 community forum, a place where you can share ideas and experiences with others in the same situation. It’s a site where you can communicate with experts and peers in different industries around the world. Look for the Gas Analysis and Analytical Communities, plus other specialty areas for opportunities to provide input, suggestions, and answers.

How Changes to Functional Safety Standards Can Optimize Fire and Gas Detection

Amanda Rahn — Tue, 21 Jan 2020 20:54:16 GMT

When a major standard goes through an extensive revision, it can take some time for users to digest and begin applying the new rules. Such is the case right now with ANSI/ISA 84 for fire and gas systems.

Design and implementation of large-scale safety systems of all types depends on standards to guide execution through all phases. Since people, equipment, and the environment depend on these systems, it is important employ the collective wisdom of standards committees. Those who work with fire & gas systems draw on ISA-TR84.00.07-2018, which recently went through a major revision. How users should interpret and apply these changes is the topic of an article in the December 2019 issue of Hydrocarbon Processing titled How Changes to Functional Safety Standards Can Optimize Fire and Gas Detection.

The 2018 edition is the first update since this technical report was initially issued in 2010, so there are many revisions. Clearly it is not practical to cover the full extent of the revisions in a single article, so we simply hit some of the highlights, letting users decide what topics merit additional consideration.

Engineers creating FGS-related safety functions and using the original 2010 technical report for guidance will now find substantial changes in the 2018 version. Most of these updates expand the range of acceptable technologies for various applications. They also add discussions on safety philosophy and offer practical guidance on implementation. These updates provide many more resources for assessing risk and configuring systems.

The article takes a forest-and-trees approach, beginning with some of the more philosophical questions, as to when fire & gas system design should begin. The emphasis is on doing it earlier, while the plant is still being laid out, rather than starting later.

Just as ANSI/ISA-84 emphasizes the concept of the safety instrumented system (SIS) lifecycle, the 2018 technical report drives designers to include the FGS design much earlier than in the larger SIS design process. This prevents looking at the completed plans and deciding how to configure the FGS to make it fit. The standard recognizes it is not enough to teach FGS designers simply how to perform a fire and gas hazard assessment, create a system and bolt it on. To be enduring, the lifecycle steps must be part of the FGS design process and integrated into every stage of a larger project for design, implementation and operation of a new plant, or an upgrade to an existing automation system.

The new technical report acknowledges that new technologies have emerged, adding new options for system designers beyond those in the toolbox when the original standard was being compiled and reviewed.

The technologies discussed in the 2010 technical report reflected the state of the art in the years just prior, basically 10 and more years ago. Since then, a broader and much improved range of sensor options has emerged, such as ultrasonic gas detectors. These can detect the sound made by a pressurized gas leak, providing immediate response rather than waiting for a gas cloud to accumulate to the point where it can be detected by conventional sensors. Most FGS implementations will need both technologies, but well-placed ultrasonic detectors can respond more quickly in critical applications.

Emerson’s Rosemount Incus Ultrasonic Gas Leak Detector is exactly the kind of sensor suggested. The Incus is an advanced ultrasonic gas leak detection system utilizing four ultra-sensitive acoustic sensors, each of which constantly monitor wide areas for ultrasound generated from the release of pressurized gas. It’s ideal for monitoring well ventilated outdoor environments because it can withstand inclement weather, wind, and gas dilution or stratification—and cope with different leak directions.

Users wanting to deploy such a sensor and apply other advances under the guidance of the standard will need to do a lot of study and work with appropriate experts, and Emerson can assist in these efforts.

You can find more information like this and meet with other people looking at the same kinds of situations in the Emerson Exchange365 community. It’s a place where you can communicate and exchange information with experts and peers in all sorts of industries around the world. Look for the Safety and Flame & Gas Groups and other specialty areas for suggestions and answers.

Improved Cooling System Performance Begins with Data

Jason Dalebroux — Tue, 14 Jan 2020 15:08:18 GMT

One of the main purposes of the IIoT, and of analytics tools like Plantweb Insight Applications, is gathering and using data to improve plant performance and profitability. This idea can and should extend to cooling system performance.

Refinery managers need to closely monitor cooling systems to avoid costly problems, and these systems are often surprisingly simple and inexpensive to monitor and control. This is the main point of my article in the November 2019 issue of Hydrocarbon Processing, Improved Cooling System Performance Begins with Data. Why is cooling system performance so important? Because it takes lots of energy and water to refine oil.

Refineries consume large amounts of energy and water to refine crude oil into products. Up to 10% of crude oil’s energy content is consumed during processing, and it takes 1.5 bbl of water to process one barrel of crude oil. Refining processes also generate large quantities of excess thermal energy that needs to be expelled into the environment using a once-through or recirculating cooling system.

That’s a lot of water and accompanying costs. Consequently, the mechanisms which handle these processes merit serious consideration.

Unless a raw water source is abundant and readily available, recirculating cooling water as much as possible is critical not only to reduce the cost of water treatment, but also to conserve the water supply. Unlike once-through systems, recirculating systems reuse the cooling water and employ evaporative cooling towers to transfer heat from the process to the atmosphere. Evaporative cooling towers have high construction, operational and maintenance costs, while consuming large quantities of water, often as much as 90% of the total water consumption in a refinery.

Yes, that’s what it said: 90% of total water consumption. The article has extensive discussion of ways to monitor the mechanical elements of cooling towers, which are well worth following up. But for right now, let’s look at the water itself and examine ways to get more out of each gallon by figuring out its condition so it can be used more effectively. Water quality in this context is calculated in cycles of concentration (COC), which compares the dissolved minerals in the recirculating water compared to fresh makeup water. A high COC value suggests water flowing through the system has picked up lots of unwanted stuff.

Increasing COC introduces several problems that can impact cooling system performance, such as corrosion, scale deposition, fouling from airborne contaminants, microbiological growth and degradation of a cooling tower’s structural integrity. The severity of these problems depends on multiple parameters such as chemical composition of the makeup water, cooling tower location, cooling system materials of construction and operating conditions. In addition, these problems are interrelated and addressing one may exacerbate the other. For example, lowering pH of the cooling water by adding acid can help control scale deposition, but may intensify corrosion and make controlling certain types of microbiological growth more difficult.

It's easy to see that the condition of recirculating water can rapidly degrade, which takes a toll on equipment in a variety of ways. There are methods to treat water in the system, but these can be costly, and trying to solve one problem may make another worse. Fortunately, these factors can be measured in real time with the right instrumentation to determine exactly what needs to happen.

Effective control of COC and chemical treatment to maintain water quality requires continuous online measurement of water quality. At a minimum, plants should continuously monitor their cooling water pH and conductivity, using temperature-compensated pH sensors to monitor the alkalinity of the cooling water, along with conductivity sensors to monitor the concentration of dissolved minerals to maintain an optimal COC. General-purpose pH sensors and contacting conductivity sensors are suitable for most cooling water systems; however, for systems with a high degree of fouling, pH sensors resistant to fouling and toroidal conductivity sensors are recommended.

An excellent place to start when looking at better instrumentation is Emerson’s Rosemount 3900 General Purpose pH/ORP Sensor. This combination sensor's double-junction reference improves its resistance to harsh environments and helps prolong sensor life. For conductivity, the Rosemount 400 Contacting Conductivity Sensor can accurately measure electrolytic conductivity in a broad range of applications from high purity water to clean cooling water. For water with an especially high COC value, there are other sensors designed to handle tougher applications.

You can find more information like this and meet with other people looking at the same kinds of situations in the Emerson Exchange365 community. It’s a place where you can communicate and exchange information with experts and peers in all sorts of industries around the world. Look for the Liquid Analytical Group and other specialty areas for suggestions and answers.

Emerson 700XA not working

Junaid Saleem — Sun, 15 Dec 2019 13:32:45 GMT

I upgraded the GC to new firmware version using MON2020. After successfully upgrading, GC rebooted automatically and could't completely start and is unable to communicate with PC after that.

LED's on the front panel are all OFF.

While LED's on backpane are all green.

LED's on CPU and I/O board are blinking green

Can anyone explain? and how much time it takes to be normal after this reboot.

Understanding Fire and Gas Systems Increases Safety

Amanda Rahn — Wed, 04 Dec 2019 17:54:53 GMT

How well do the people in your plant understand your fire and gas safety systems? This is an important question as the answer may affect their safety in the event of an incident.

Now I am not asking if your people are capable of designing a safety system. Such work must be left to professionals for obvious reasons. But at the same time, if most of the people trained to work in a potentially hazardous environment were to look at the red sensor mounted near a big flammable liquid storage tank, would they know what it is for?

This is not a rhetorical question, and the reasons why knowing the answer is important is the main topic of a recent article published at automation.com in November 2019, Understanding Fire and Gas Systems Increases Safety. Like a smoke detector at home, a fire and gas system, once installed, can easily fade into the background. When workers acquaint or reacquaint themselves with the critical roles provided by fire and gas systems, it improves overall safety. But how does might this work?

The article goes into greater detail, but think about how safety experts design systems in accordance with standards such as IEC 61511 and ANSI/ISA 84. They begin by analyzing the plant and considering what potential hazards might be present. Where there is crude oil and natural gas, there is potential for fire, but also the presence of toxic gases such as sulfur dioxide. You can come up with many other examples. Workers in those plants undergo a great deal of training about the plant environment and what they might encounter during an incident.

Plant safety systems reflect those realities in the selection of sensors and safety control systems. For the example, there must be a toxic gas sensor (Emerson’s Rosemount 928 Wireless Gas Monitor for the H₂S) and flame detector (from the Rosemount 975 Flame Detector family selected to reflect the potential fuel sources available.), positioned strategically to give the greatest degree of protection. Again, the article goes into greater detail so give it a full reading.

People in the plant should know what those sensors are designed to detect. A trained and experienced worker should be able to point to one and say, “That’s for H₂S, and the one over there is an infrared flame detector. If it is triggered, it will sound a horn and release fire suppressant foam through this area. We head for the exits and gather in our mustering area.”

Every time workers walk through the plant and look at those sensors, they should be reminded of what they are there for, and what hazards may exist just a few feet away. They can also watch for situations where there is potential for a false alarm, such as a welder doing work within sight of a flame detector, or a careless person leaving something in a place that obscures a flame sensor’s viewing area. These work practices are most effective when every individual understands the importance of those devices and the parts they play in keeping the plant, its workers, and the surrounding community safe.

Gas Testing for Electrochemical Gas Detectors

Edward Naranjo — Wed, 27 Nov 2019 14:56:56 GMT

Electrochemical sensors used for fixed point toxic gas detection have advanced considerably over the last years. New designs are more compact, resilient to adverse environments, and reliable. Novel designs are also revealing more failure types and providing information on sensor health well before the device can no longer perform its protective function. Such diagnostics are prompting end users to consider maintenance routines in a new light; most evident perhaps in the extension of periodic inspections and tests. In some instances, operators are forgoing periodic gas testing in favor of monitoring parameters that correlate with sensor health. Nonetheless, such complete reliance on leading indicators of sensor health is risky. As end users modify maintenance protocols to better take advantage of predictive health intelligence diagnostics, they should consider the role of periodic gas testing and diagnostics in electrochemical devices.

Electrochemical sensors respond to gas accumulations by reacting to the target gas and producing an electrical signal proportional to the gas concentration. A typical electrochemical sensor consists of a sensing electrode (or working electrode), a reference electrode, and a counter electrode separated by a thin layer of electrolyte (typically hydrochloric or sulfuric acid; see Figure 1). The electrolyte provides ionic electrical contact between the electrodes with the aid of hydrophilic separators. Gas that comes into contact with the sensor first passes through a small capillary opening and diffuses through a hydrophobic barrier to reach the sensing electrode. The gas then reacts at the surface of the sensing electrode oxidizing or reducing the gas to be measured. A high surface area catalyst is used to optimize sensor performance. All electrochemical sensors for fixed gas detectors operate in the amperometric mode, meaning they generate a current that is linearly proportional to the fractional volume of target gas.

Because high availability is essential for safety devices, most gas detector manufacturers make provisions for circuitry that monitors sensor health. A voltage or resistance across the sensor can be indicative of an incipient failure provided the signal and allowable variance in parameters for a “good sensor” are understood. Deviations from a baseline beyond certain tolerances or patterns of the signal can therefore suggest degradation in sensor performance. Such diagnostics have contributed to the wider acceptance of electrochemical gas detectors in the process sector, where devices must operate continuously in low demand conditions for several years. The advent of predictive health diagnostics has also contributed to a more robust and efficient management of detector installations. As work orders for repair are issued only to those devices that need attention, the risk of inadvertently damaging well-running equipment is minimized.

Although the benefits of improved diagnostics must be recognized, they cannot be taken to suggest periodic testing should be reduced or eliminated. Like periodic testing, diagnostics are imperfect and it is unrealistic to assume they will detect all failures. Consider a detector may fail to detect gas if its membrane or sinter is blocked by dirt. Even a small amount of impacted dirt can have a significant effect on the membrane’s permeability and access of gas through the capillary diffusion barrier, reducing the device’s effective response speed. Prolonged exposure to silicone vapors can also have a similar effect. In both instances, the inhibition of sensitivity may not be revealed through diagnostics.

Invariably, periodic gas testing must be part of a maintenance regime. For point gas detectors, periodic gas testing involves applying a well-known gas concentration to the device. If the device reports a reading that is within tolerance of the applied gas concentration and responds within an adequate amount of time, it can be said to operate as specified. The test is simple and easy to implement. One advantage of gas testing that is often overlooked is that it serves as a forcing mechanism for visual inspections. A visual inspection can reveal signs of exposure to alkaline metals, which form salts and can cause sensor drift. Excessive rust around the sensor may also be indicative of exposure to corrosive materials like chlorine, hydrochloric acid, and hydrogen sulfide. Additionally, a damaged diffusive barrier – a splash guard, insect guard – can be quickly detected by visual inspection. Equally important, the gas test is an enabler for a full test of the safety loop. Such holistic tests ensure sensor activation and fire and gas system response, including alarms and isolation of equipment, are consistent with fire and gas system design.

It is not often that a detection technique can be as improved for long unattended operation. End users have responded to new advances in electrochemical cell design with higher rates of product usage. Nonetheless, the adjustments of maintenance practices as a result of new diagnostics must be measured. Diagnostics cannot test the permeability of gas across a membrane or diffusive protective barrier. The intent should be to increase the percentage of failures that are revealed from testing and diagnostics. In an imperfect world, the combination ensures device availability is maximized.

References

Chou, J. 2000. Hazardous Gas Monitors: A Practical Guide to Selection, Operation and Applications. New York: McGraw-Hill Professional.

Mari, C.M. and Barbi, G.B. 1992. Electrochemical Gas Sensors. In Gas Sensors: Principles, Operation and Developments, ed. G. Sberveglieri. Dordrecht The Netherlands: Kluwer Academic Publishers.

Riddle, D. 2009. Danger and Detection of Hydrogen Sulphide in Oil and Gas Exploration and Production. Petro Industry News 10: 6-7.

Siddique, M. 2008. The Search for the Perfect Sensor to Monitor Hydrogen Sulfide. Gases & Instrumentation 2: 24-27.

Save Money, Time and Water with this Free Chlorine Measurement Approach

Sherri Renberg — Wed, 16 Oct 2019 16:35:54 GMT

Water plant professionals know that when it comes to measuring free chlorine, amperometric technology has many advantages – and one significant disadvantage. The measurement is pH dependent. As a result of this disadvantage, many plant managers find themselves balancing the pros and cons of amperometric versus colorimetric technologies and sometimes finding themselves with no ideal choice.

In a recent article in WaterWorld, Michael Francis, global product manager, Emerson, discussed this critical choice. In the article he examines the nature of free chlorine measurement and why it is inherently pH dependent. He then goes on to analyze the benefits and disadvantages of colorimetric and amperometric measurement methods. Colorimetric systems require expensive reagents that can cost between $750 and 1,000 a year per system. Since most water authorities have hundreds of systems, the dollars really add up in direct costs, and especially, in personnel time.

Michael discusses the significant benefits of reagentless amperometric technology, and then reviews the typical ways that water plants have dealt with the need for pH measurement, most often requiring the use of an auxiliary pH analyzer. These systems need complex integration and require a large flow sample which overuses water and raises ongoing costs.

Ultimately, Michael outlines an elegant solution that allows water plants to take full advantage of the benefits of amperometric measurement with very few downsides. An integrated approach saves water plants money, time and water. Check out the complete article HERE.

How do you measure free chlorine?

Wireless gives digital transformation wings

Emerson Exchange News — Wed, 25 Sep 2019 01:11:46 GMT

Jim Montague

Many ingredients, such as software, networking, microprocessors, cloud computing and the Internet of Things, combine to make digital transformation possible, but the one that can help as much as the others and might be overlooked is wireless technology. Because it can take industrial networks into previously inaccessible locations and gather signals that used to be stranded, wireless can give users more of the data and benefits needed to boost their digital-transformation efforts and justify investing in them.

"We believe there are three main elements in using wireless to aid digital transformation. These elements include secure connectivity and choosing the right wireless network for transferring data to where it can be analyzed; determining how the infrastructure will support pervasive sensing; and, in our case, two new Plantweb™ digital ecosystem applications in the areas of asset health for pre-configured analytics and workforce effectiveness for digitally enabled users," said Tom Bass, product management director for wireless with Emerson’s Automation Solutions business, at Emerson Global Users Exchange 2019 in Nashville, Tennessee.

Choose wireless wisely

"There's been a massive deployment of wireless in the process industries during the past 12 years, and this has led to an increase in choices. However, users still need to decide which wireless to invest in and what criteria to use," explained Bass. To determine which wireless infrastructure is most suitable, it must:

fit with the user’s existing security architecture
possess simplified network management
be certified for hazardous locations and conditions
have deployment flexibility
be future-proof.

"Field and plant networks must work seamlessly to successfully deliver operational analytics solutions, but their users also have to address some unique industrial automation features," added Bass. "For example, plant networks have to account for different data rates and ranges and whether they're licensed or unlicensed protocols. Meanwhile, field networks have to address update rates, battery life and scalability issues."

"There's been a massive deployment of wireless in the process industries during the past 12 year." Emerson's Tom Bass reminds users to choose wireless wisely at Emerson Global Users Exchange.

Hardware lends a hand

To give its users some tangible assistance in deploying wireless for digitalization in those fields or plants, Emerson is bringing its 13 years of experience in pioneering and implementing wireless to bear and partnering with longtime collaborator Cisco on a new wireless-networking solution. Combining Emerson’s expertise in industrial automation and applications with Cisco’s innovations in networking, cybersecurity and IT infrastructure, the new Emerson Wireless 1410S Gateway with the Cisco Catalyst IW6300 Heavy Duty Series Access Point combines the latest in wireless technology with advanced WirelessHART sensor technology, delivering reliable and highly secure data, even in the harshest industrial environments.

Wireless 1410S Gateway access point provides enhanced Wi-Fi bandwidth necessary for real-time safety monitoring, including Emerson’s Location Awareness and wireless video. These applications enhance personnel safety practices, improve plant security and help to ensure environmental compliance. A reliable and fast connection between devices and people streamlines decision-making by providing real-time analytics. It also enables a mobile workforce to virtually come together, collaborate and resolve critical issues quickly. Wireless 1410S Gateway also supports mobile applications that offer immediate access to process control data, maintenance information and operation procedures, enabling improved plant productivity and worker safety.

Wireless 1410S Gateway features:

Class I, Div. 2 certification
flexible connectivity with three power-over-Ethernet (PoE) and one small-form-factor-pluggable (SPF) port
ac/dc and PoE for power redundancy
fiber capability
lightweight, compact design for simpler deployment in extreme temperature ranges
up to 200 devices on WirelessHART, and up to 100 devices on ISA100
resilient mesh-architecture support based on 802.11 AC Wave 2
improved temperature range of -50 °C to 75 °C.

Apps and sensing on tap

Back on the software side, Emerson has released two new Plantweb infrastructure analytics apps, which are part of the overall Plantweb Insight analytics portfolio that already has seven other apps.

Power Module Management provides calculated insights about power-module status, estimated remaining life and estimated total lifespan. Its benefits include access to power-module status from multiple Emerson gateways, effective maintenance planning to replace power modules and awareness of short-lifespan power modules.
Network Management provides calculated insights about network status, network best practices and gateway load. Its added features include a network diagram, consolidated syslog alerts, and an IP address, a network ID and firmware version lookup.

In addition, Bass added that Emerson has released three more technologies to its 21-member Pervasive Sensing portfolio. Its new solutions include:

location tags and anchors that can digitally transform facility safety with a WirelessHART-based location awareness system
expanded toxic-gas monitoring capabilities for H₂S, CO and O₂—similar to the H₂S sensor, the CO and O₂ depletion sensors are smart sensors that store calibration data on the sensor itself
AMS wireless vibration monitoring to provide triaxial vibration and temperature monitoring with embedded PeakVue analytics to predict bearing issues.

"All of these capabilities demonstrate why investing in an appropriate wireless infrastructure is part of the foundation for digital transformation success," concluded Bass.

Digital tools improve collaboration, speed and productivity

Emerson Exchange News — Wed, 25 Sep 2019 01:06:50 GMT

Dave Perkon

Emerson is transforming how its customers work through the personalized digital experience called MyEmerson. "Expectations are changing, and digital is enabling those expectations,” said Brad Budde, vice president of digital customer experience with Emerson’s Automation Solutions business, during Emerson Global Users Exchange in Nashville, Tennessee. “U.S. households are spending more than six hours a day with digital media, and the same kind of trend is happening in e-commerce. The consumer expects speed and a wide range of options and choices, and they don't have time to run errands. Those expectations, personally at home, are being brought to work."

Speed and preferences to use a self-service, personalized tool to complete tasks and conduct business are important, especially to engineers, said Budde. Emerson identified three key personas getting value out of these digital capabilities. These include engineers working with CAD drawing downloads and engineering tools who are digitalizing to size and select products; procurement managers and departments looking for digitalization to create operational efficiencies; and plant technicians digitalizing the way they do work to be more informed when they go on-site and use mobile tools, digital processes and workflows to execute their work.

"Improved collaboration, speed and productivity are realized by moving historically off-line work processes online using digital tools." Emerson's Brad Budde announces MyEmerson as a personalized online user experience at Emerson Global Users Exchange in Nashville, Tennessee.

"Improved collaboration, speed and productivity are realized by moving historically off-line work processes online using digital tools," said Budde. "In reaction to that, Emerson has announced MyEmerson as a personalized online user experience. We have had this capability for a few months now and are rolling it out publicly.” It currently has more than 7,000 active users.

MyEmerson has been a seamless experience for customers, and has several key capabilities. It includes MyWorkspace, where engineers can size and configure products, create drawings and collaborate. The MyTransactions component allows information to then be shared with the procurement department for price, quotes, planning and order history. The resulting information is moved to MyAssets to view asset records, access product documents, maintain assets and schedule service. MySoftware provides "front-door" access to download and manage licensed software. MyTraining lists training records and relevant training courses. And, finally, MyPreferences lets the user tailor the experience.

"MyEmerson provides a customer a single place to do work," said Budde. "For example, the digital experience may include specific content for a flow asset based on its serial number. However, it's more than just a singular personal experience. It's also important to collaborate with your peers."

An example of how that would work may start with the installation of a wireless pressure gauge for pump-seal monitoring. "Once the ROI is proven, the reliability supervisor may decide to scale it across the enterprise," said Budde. "Using the digital experience, supervisors can look at MyAssets to understand how the original solution was implemented. That information can seamlessly be used in the MyWorkspace environment, where they can collaborate with engineers and change any specification needed to localize it as needed. They can then pass the information on to the procurement manager, who can help plan delivery in MyTransactions based on lead times, delivery dates and order histories. The procurement manager then coordinates and communicates with the plant technician to ensure successful delivery. The technician can then install the device and the operations team updates the workflows and applies analytics to realize the ROI at scale. This whole loop brings together operations and all the other people who work together using these digital tools in the MyEmerson collaboration environment, meeting the digital expectations in the workspace."

MyEmerson is significantly faster than the traditional off-line methods of the past, said Budde. "For example, compared to the off-line method of creating CAD drawings based on the information found in catalogs, the new digital capabilities of simply downloading a drawing and importing it into the CAD system is 93% faster, saving several hours," said Budde. "Digital engineering tools show a similar time savings. Building the part configuration using a visual configurator is very fast. Digital procurement tools are fast, as well. Instead of passing several emails to get all the information and quotes needed to get a part ordered, it can be done immediately online."

The digital experience can help plant technicians, too. "In the old way, the technician would find the serial number and go to the manufacturer to try to get the history of the device," said Budde. "In the new way, the technician can look up the serial number in MyEmerson and receive the content immediately."

The field-service tools already deployed have helped technicians get the right information, the right processes and the right training in advance of executing that service, continued Budde. "What we found is, in the old way, our first-time fix rate was 75%,” he said. "With the new digital tools in MyEmerson, the first-time fix rate went up to 85%. We are better executing service using digital tools."

Specifying Fire and Gas Detection Systems to Improve Operations

Edward Naranjo — Fri, 20 Sep 2019 14:34:56 GMT

One of the analogies we hear from time to time is describing something as a three-legged stool. Rather than something to sit on, this illustration helps us understand a concept that depends on three elements working together to make it effective. With the stool, taking away any one leg causes it to collapse, regardless of how strong the other two legs are.

Such is the case with fire and gas detection. An effective gas detector has to deliver in three areas: accuracy, response speed and measurement range. We discuss these elements in detail in my article in automation.com’s Instrumentation & Sensors eNewsletter for August, 2019, Specifying Fire and Gas Detection Systems to Improve Operations.

Accuracy relates to the trustworthiness of the reading to reflect the severity of a hazard, while fast response enables early warning. A highly accurate instrument that does not respond quickly to a dangerous situation is unsuited for service in a safety instrumented function. Similarly, a device whose reading cannot be trusted but responds quickly on exposure to an agent is of little use as a safety device. Finally, the device must respond within the relevant range of the target gas. A good sensor strikes a fine balance between accuracy and speed, while rejecting false trips and alerting when dangerous concentrations are measured.

The article examines all three areas, but one often misunderstood is accuracy. Gas detectors looking for flammable or toxic gases must measure small amounts of the subject product accurately. In fact, well designed sensors should have their highest accuracy in the low end of their range so they may provide early warning of incipient leaks.

As a result, accuracy becomes a key consideration when setting alarm limits. If the range of plus or minus is too wide, alarm limits cannot be set at the most desirable points. For instance, if the nominal alarm level is 40 % LEL (lower explosive level) and the device accuracy is ±3 % LEL, the instrument should be configured to alarm at 37 % LEL. The sensor’s accuracy dictates how the alarm level is set, rather than the ideal value, which can put it perilously close to where false alarms can sound, disrupting production.

To improve operations, alarm levels should be set as close to ambient conditions as possible without causing false alarms. Emerson’s Net Safety Millennium II SC310 Catalytic Bead and SC311 Point Infrared Combustible Gas Sensors are designed to provide exactly that kind of performance. The SC310 and SC311 provide versatile, robust and field-proven performance in a rugged package designed for the most extreme industrial environments. For flammable gases, % LEL detection is fast and reliable with simplified field serviceability using the M2B, M21 or M22 universal transmitters.

You can find more information like this and meet with other people looking at the same kinds of situations at Emerson Exchange and in the Emerson Exchange365 community. It’s a place where you can communicate and exchange information with experts and peers in all sorts of industries around the world. Look for the Flame & Gas Group and other specialty areas for suggestions and answers.