IIoT & Digital Transformation Forum - Recent Threads

OPC UA Concurrent Session Expectations in Production

Franz Valmonte — Thu, 12 Feb 2026 06:28:28 GMT

Hi all,

We are currently benchmarking OPC UA performance for the DeltaV Edge Environment. Since OPC UA is one of the supported data egress interfaces on DeltaV Edge, we are evaluating how many concurrent OPC UA sessions can be supported while maintaining optimal system performance.

To help guide our benchmarking assumptions, could you share:
How many concurrent OPC UA client sessions you typically run in production?
What types of clients are connected, for example historians, analytics platforms, dashboards, or custom applications?
Whether you have experienced any performance constraints tied to session count or monitored items?

Our goal is to align our internal performance targets with real-world deployment patterns. Appreciate any input you can provide.

VMware ESXi Versions in Use for Plant or Corporate Virtualization

Franz Valmonte — Thu, 12 Feb 2026 06:17:54 GMT

Hi Everyone,

We are evaluating support for deploying DeltaV Edge on a virtual machine, rather than requiring a dedicated Dell R660xs server. As part of this effort, we are starting qualification with VMware ESXi as the hypervisor.

To help us scope and prioritize validation, could you share:

What version of VMware ESXi you are currently running in production?
Whether that ESXi host is located within the plant environment or in a centralized corporate datacenter / cloud?
Who manages it, plant OT/IT or corporate IT?
Any plans to upgrade within the next 12 months, particularly to ESXi 9.0?

Our assumption is that many environments are currently on ESXi 8.0, but we want to validate this before finalizing our qualification approach.

Appreciate any input you can provide.

Initializing a Cascade across a DeltaV OPC UA Server

SteveB — Thu, 20 Feb 2025 16:29:34 GMT

Hi,

I want to create a traditional cascade between a server-based app and a DeltaV Regulator (e.g. PID). I am not that familiar with DeltaV or OPC UA so wanted to see if anyone could offer guidance.

To initialize a cascade between two DeltaV Regulators requires a secondary to send a BKCAL InitReq and BKCAL Value to its primary in the form of an 8-bit status word (ST) and a floating point value (CV). It seems as if the CV and ST must be coupled during transmission between two DeltaV regulators because the secondary's ST requests initialization, and the CV sent along with it contains an initial value for the primary's OUT parameter - to ensure bumpless transfer.

However, if one were to establish a cascade ACROSS a DeltaV OPC UA server, then it seems as if this InitReq/Value coupling is lost as both appear as separate and independent values in the OPC UA server. The concern here is that if a server-based app reads an BKCAL InitReq, but for whatever reason the BKCAL value has yet to update, then the server-based primary might initialize its OUT to a stale value (maybe only slightly old, but that lack of determinism could be problematic).

The traditional way that third-party app providers have solved this problem seems to be reading up the DeltaV regulator SP every cycle and then incrementing it before writing it back down, but I was wondering if there might be a more elegant solution where initialization only occurs when the cascade is closed.

So my question is: Is there a way to ensure that the correct BKCAL value is read from a DeltaV OPC UA server along with a BKCAL InitReq? I have thought of reading the InitReq first (ST) and then going back for the Value (CV), but I imagine that there are edge cases where the result is not deterministic. My back-up plan is just to initialize every execution cycle. Thanks.

Rosemount 1420 firmware Upgrade from 3.9 to 4.8

Cesar Marquez — Fri, 10 Jan 2025 13:16:44 GMT

Best regards, I have a problem with a 1420 since it has firmware 3.9 and only accepts tls 1.0 connections to be managed, and this has been deprecated by almost all browsers. I thought about updating it to the latest version, however I don't see a procedure to do so since the guide is made for firmwares 4.5 onwards. Is it possible to update a 1420 from version 3 to 4? MODEL:1420A3A3AN6WL2. greetings.

SIS CHANNEL

shouy — Thu, 23 Feb 2023 05:41:19 GMT

does anyone know why Emerson limit the "Only 48 of the 96 LS CHARM slots can be configured as output LS CHARMs"?

Lotus Notes to Office 365 Migration Tool || Step-by-Step Guide

divyachauhan — Fri, 25 Nov 2022 08:06:42 GMT

Nowadays Lotus Notes came along with many drawbacks like as not being cost-effective, difficulty to maintain data consistency, et cetera, and because of these reasons users want to switch their Lotus Notes accounts to another emailing platform. Office 365 is the best platform to replace it with Lotus Notes. There are two ways to conduct the migration task; manual or professional is that two ways. Through manual method, users get uncertain data and the whole process is time-consuming as well. Moreover, using professional third-party tools like Shoviv Lotus Notes to Office 365 Migration Tool, users can effectively execute the task of migration from Lotus Notes to Office 365.

It can migrate multiple Lotus Notes files into Office 365 at a time without affecting the speed of the outcome. This tool maintains data integrity and folder hierarchy at the same time. It includes advanced features like incremental export, which helps to resume the task from the last ended point and prevent your data from duplicity. With the help of its filter option, users can filter desired items according to their choice. It can export Lotus Notes files into PST, EML, MSG, and HTML file formats. Users can download its free trial version to know its full working and functionality without investing in it.

virtual SZ & CSLS in SIS internal FAT

shouy — Mon, 21 Nov 2022 02:48:13 GMT

does anyone tall me how to use the Virtual CSLS tool with in my FAT system ,where can I download the "DeltaV Virtual studio" and open the studio?

SIS_PDS_Virtual_DeltaVSIS.pdf

1420 GW homepage does not load

AfzalSJ — Wed, 13 Apr 2022 23:57:42 GMT

Hi All,

A 1420 DVready gateway does not load the homepage completely. It gets stuck on the Emerson banner and goes no further.

Tried resetting with #2 dip-switch multiple times but no change. Also tried on both primary and secondary DV IP addresses and multiple browsers/machines.

I am unable to use this GW at all. Would appreciate any support please. Thank you and Regards.

IC694PWR330 indicator sequence changed?

Jack.Zhang — Sun, 26 Sep 2021 04:15:41 GMT

Just look at the picture！

Changing Registers Sequence ModBus

Dmitrii Kapitonov — Thu, 09 Sep 2021 06:37:46 GMT

Hi there!

DeltaV 13.3.1

I'm using a device having a non-standard Modbus register sequence, I need to get Float Value. Assume there is temperature 61.2°С It means registers I must receive are 250 204 116 66, but the used device has register sequence such as 116 66 250 204, so I have to change the register sequence. Currently I get incorrect value such as -4.234+012 or similar. After describing problem, I have two ways for solution.

First, I can change the sequence using custom FB in ControlStudio and receive two16bit integer instead of float, example at the picture below. This way is easier for me, but I want to find more flexible way to solve the problem without using additional FB.

Second, I can reconfigure Standard SI Module to programmable SI Module and use SampleCustomProtocol ModBus by Mynah , I hope someone used it somewhen, but I have a problem when I full textbox up in the Special Data Tab the necessary value as sown at the picture below and download ProgSI Module, Registers don't change sequence. Maybe someone can help me to find a way to solve the problem.

If someone knows others ways to change registers sequence, I'll be glad to read them.

Thanks!

SIS NET Repeater Link Status BAD

Ravi Chandra Penumarti — Sat, 07 Aug 2021 11:24:00 GMT

Hi Everyone

SIS NET Repeater with Hardware rev 9.18 and Software revision 2.1 are installed in our SIS Network. Under Repeater diagnostics - Repeater Connection List we found Link Status as BAD. All the parameters under diagnostics of individual repeaters is GOOD. Please suggest the probable cause.

Thank You

Communication of DeltaV Database like Event Chronicle with External BigData

Hassan Akhtar — Sat, 13 Feb 2021 07:05:18 GMT

I am trying to link up DeltaV Database with our BigData service out of DeltaV system. I think DeltaV continous historican is not a structured database therefore we can only access within DeltaV System. But DeltaV e Event Chronicle is somehow available out of DeltaV system. What you people think about the DeltaV database while comparing with other Distributed Database systems? Because in smart industrial system databases are being connected with central BigData systems.

Profibus Communication Between Delta V Controller and Siemens S7 300 CPU

Goktug Duman — Sun, 11 Oct 2020 06:40:36 GMT

Hi,
I want to make a profibus connection between CPU 315-2DP and a Emerson Delta V controller and read data from S7 system. I installed a Profibus DP card to emerson system and it is master as default ithink. So CPU 315 must be slave i think. I installed gsd file of CPU315 to emerson system. But I couldn't establish the connection. Can anyone tell me how to make the connection? I made the adjustments on emerson, like gsd file, creating device, port, channel, baud-rate etc. But I dont know what to make on siemens side. Is there anything to do on siemens side?

Control your factory remote

Leo Mennen — Thu, 30 Jul 2020 13:19:49 GMT

Our customer has a carwash, use an Series9030 GE Fanuc PLC with a datapanel
Now he did switch to an RX3i from Emerson and a Quickpanel+ from Emerson

he can use Target view on a remote PC to connect to the panel, works fine

Only he wants to do that from an iPhone?

What is the best solution?

How do I set this up?

Thanks and Regards, Leo Mennen

Automate Manual Inspection Rounds

Dan Carlson — Mon, 01 Jun 2020 19:47:25 GMT

Sometimes technologies are adopted for their own sake, but it is much better when an advance as important as digital transformation begins by solving a problem.

Digital transformation has been used to solve countless problems and improve all manner of operations, but let’s concentrate on one. My article in the May 2020 issue of Chemical Processing, Automate Manual Inspection Rounds, focuses on how companies use their internal personnel resources, and how they can get more from those people through improvements in automation.

Highly skilled and increasingly valuable plant personnel often must perform these mundane and repetitive tasks, moving through the site to check the status of instruments and assets, and documenting their findings using pen and paper. These results then get manually entered into some type of maintenance management system, a process prone to data entry errors. Applying digital tools to automate manual rounds frees these personnel to do higher level tasks such as analyzing collected data to improve operations.

Some people see digital transformation as a means to replace people, but in reality, it provides opportunities to upskill your operators and technicians, and then put them to work doing higher-value tasks. It also reduces their exposure to potentially hazardous situations by reducing the amount of time they may have to spend in the plant. So how does digital transformation solve the manual rounds question? Sensors installed on equipment assets capture data rather than human beings.

Today, using wireless instead of wired instrumentation to gather and transmit data can cut costs and time for connecting each point by up to 75%. Wireless instrumentation enables plants to automate most manual rounds, enabling data gathering even for lower value and less critical assets that never could justify traditional signal wiring. High quality data from the field allow assets to effectively and continually signal their status. With such inputs, analytics can provide decision support, enabling data-driven work practices and improved efficiency.

So there’s the critical trade-off: A plant uses a very costly and scarce asset—people—to do these tasks because management thinks it’s too expensive to add sensors. With a little analysis, this proves to be a false economy, particularly if considered in light of how inexpensive it is now to deploy sensors using WirelessHART networks. A case-in-point, consider monitoring pressure relief valves (PRVs) using Emerson’s Rosemount 708 Wireless Acoustic Transmitter.

PRVs prevent overpressure conditions but, when actuated, may release hazardous pollutants into the nearby area. A plant must report these releases to the appropriate regulatory agency. If detection depends on a visible telltale signal, like a sock, that is inspected every eight hours, then the agency might assume the release lasted for eight hours. In contrast, an acoustic wireless transmitter can provide 8-sec. update rates with long battery life, dramatically improving the timeliness of release reporting while also confirming the PRV has reseated and the release has stopped.

This is only one example of how a simple sensor, working with as the data collection and analysis platform, can result in an substantial improvement. This type of installation performs monitoring, continuously, 24/7—rather than waiting for operators to find a problem—if they’re even aware something untoward is happening.

So where are you still depending on manual rounds to find problems before they escalate into something bigger, more damaging, and more expensive? Where could you benefit from continuous monitoring?

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?

Monitoring Pressure Relief Valves as Part of a Digital Ecosystem Reduces Cost and Improves Performance

marcio donnangelo — Thu, 28 May 2020 03:59:53 GMT

Pressure relief valves are supposed to protect your facility. Do you know they will perform as designed when needed, or are they just costing you money?

The problem with PRVs is that it’s difficult to know if they’re working or not. In their basic forms, they have no visible mechanism or electronic elements able to send a signal. Worse, after an over pressure incident, they might not close completely, resulting in a constant leak of product from the process, causing financial losses and possible regulatory issues.

Fortunately, there is a solution to the problem, and it’s the primary topic of our article in the April 2020 issue of Processing, Monitoring Pressure Relief Valves as Part of a Digital Ecosystem Reduces Cost and Improves Performance. The key point being: monitoring saves money, but it is difficult to do without using new technologies.

As safety devices, PRVs are mechanically self-operating without the need for any electronic components or external support to function. Consequently, they are typically off-grid with no built-in mechanism capable of reporting their condition or activity via an emergency shutdown system (ESD) or distributed control system (DCS). If operators want to know what is happening with a particular PRV, they typically rely on local inspection or monitor normal process pressure measurements for indication of operation near the PRV’s setpoint.

Operators need to know when a valve has opened due to an overpressure incident and if it has re-sealed itself after an incident.

With an enclosed system, it is often not possible to see if a valve does not fully reseat itself and close completely after an overpressure incident. The valve mechanism inside a PRV of either type could be seated incorrectly, leading to a standstill leakage. Such leakage may be so small as to be undetectable by process instrumentation, such as pressure transmitters and flow meters. For hours and perhaps days, product could be flowing to the recovery system unnecessarily, reducing production and plant profitability. How can troubleshooters determine when this is happening, and what specific PRVs are affected?

That’s the main problem—PRVs can leak—but there’s an easy way to tell when this is happening, just add a simple device to the valve to determine is open, closed, or somewhere in between. One option is . These can be mounted on any type of PRV by simply attaching it to the outlet pipe where it can listen to any noise made by a valve that’s fully open, or just simmering and passing a slow but constant leak of product. This is the insidious problem, and it can cost companies lots of money.

The importance of detecting leakage as soon as it starts is driven by the compounding effect over time. A mere 0.1% leakage, if left unaddressed for a year, equals a full release from a PRV for six hours. The effect is multiplied into a huge problem when considering the total population of PRVs in a process unit or overall plant. A study from 10,000 PRV service records presented an astonishing result indicating that 20% of installed PRVs leaked below 50% of set pressure, so many valves may have been leaking all the time. Even worse, 8% of valves surveyed leaked so excessively they did not pop correctly in the test.

Mounting a Rosemount 708 on a valve and sending its data via WirelessHART to a Plantweb Insight Pressure Relief Valve Application is the ultimate setup for a comprehensive monitoring approach at minimum cost and complexity.

So, ask yourself this: Can you account for all the product going into the collection systems from your PRVs? Is it from acknowledged overpressure incidents? Or is it always there, but without a clearly identified source? Maybe it’s from leaking PRVs, and it’s time to get a handle on the problem by monitoring what they’re doing. Now you know how to do it.

Let’s hear about your situation. Are you doing any monitoring of PRVs?

How IIoT Data Can Improve Heat Exchanger Performance

Brian Joe — Wed, 15 Apr 2020 20:33:10 GMT

How many heat exchangers are running in your plant? Dozens? Hundreds? A tougher question: How efficiently are they running?

Maybe you know the answer to the efficiency question, but based on our collective experience with countless plants, few operators can quantify performance for more than their most critical and expensive heat exchangers, and even that’s a stretch in many cases. This doesn’t have to be the case today, given the availability of monitoring equipment able to use IIoT-supported networks.

This is the main point of my article in the March 2020 issue of Process Heating: How IIoT Data Can Improve Heat Exchanger Performance. As you know, heat exchangers come in every imaginable configuration and size, but there are underlying similarities.

Heat exchangers depend on complex internal geometry to provide a large amount of surface area. This can create convoluted internal flows, small passages prone to plugging from debris or fouling due to solid deposit accumulations. Such plugging and fouling reduce heat transfer efficiency and can limit throughput when severe enough. These problems drive up operating costs while capacity goes down, which can reduce the overall process performance. If cooling capacity is critical for a potentially hazardous exothermic process, process safety could be threatened.

Estimates suggest that across refineries in North America collectively, heat exchanger inefficiencies cause annual losses in the billions of dollars. Since you want to save money, ask yourself, how do you know when such problems are forming? Few heat exchangers have sufficient monitoring equipment to collect much useful data. Fixing this deficiency is where the IIoT comes in.

Determining how efficiently a heat exchanger is operating depends on measuring what it is doing. This can be accomplished with instrumentation that includes, at a minimum, devices measuring:

The process fluid temperature differential (inlet compared with outlet) and flow.
For liquid-to-liquid designs, the transfer fluid temperature differential and flow.
For air-cooled designs, the cooling air temperature and flow.

Installing these instruments, today is much easier than it used to be with traditional wired approaches. Pervasive Sensing Solutions using WirelessHART, which can interface with IIoT-based applications, simplify the task and make it far less expensive.

Of course data alone doesn’t help very much without appropriate analysis, and this is another area of vast improvement provided by tools such as Emerson’s Plantweb Insight Applications. When fed by data from WirelessHART instruments, Plantweb Insight offers instant visibility to key assets, including heat exchangers, enabling you to make better, faster decisions to digitally transform your operations. Engineered with machine learning-based asset models and analytics, this solution easily integrates with existing infrastructure and features intuitive navigation across a web-based visualization environment.

These types of applications — combined with new WirelessHART instrumentation options — provide capabilities that previously have not been available. With IIoT and wireless technologies, continuous monitoring is practical and less expensive to install and operate. Such pervasive sensing combined with analytics can reduce unplanned production losses, cut maintenance costs related to heat exchanger cleaning and reduce energy use.

So where are you on the efficiency knowledge scale? Do you have a good handle on things, or do you wish you knew more? You can tell others about your situation and experiences at the Emerson Exchange 365 community forum, a place where you can share ideas and experiences with others facing the same challenges. It’s a site where you can communicate with experts and peers in all sorts of industries around the world. Look for the Wireless and Essential Asset Monitoring Communities, plus other specialty areas for opportunities to provide input, suggestions, and answers.

Insidious Corrosion of Fixed Equipment Detected Via Predictive Maintenance

Jake Davies — Wed, 01 Apr 2020 15:10:40 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?

VIDEO: A Cost-Saving Approach to Gaining Asset Visibility with IIoT

Rich Carpenter — Wed, 25 Mar 2020 20:31:06 GMT

You don’t have to be a pioneer to explore the benefits of IIoT. In this video, I will explain the logic behind a more iterative approach to upgrading your assets to fit the growing demand for IIoT at your own pace.

www.youtube.com/watch

Would IIoT help you solve a visible issue? Unsure where to start? Start a conversation or ask a question in the Emerson Exchange 365 community by replying below.

If you would like to learn more about our Digital Roadmap Services watch this video.

Wireless Technology Modernizes Power Plant Performance Monitoring

Juan Panama — Thu, 19 Mar 2020 16:59:42 GMT

We know that WirelessHART makes field instrumentation installation easier and less expensive, but in certain situations, such as temporary installations, it can be more convenient.

One company has taken advantage of WirelessHART’s capabilities in a big way to make major deployments of instrumentation on a temporary basis. WirelessHART has become a critical tool in their kit and we can all learn from their experience.

In the January, 2020 issue of Process Heating, Wireless Technology Modernizes Power Plant Performance Monitoring we discuss the experiences of a reliability and efficiency development team within a major electric utility company. These people spend their time going from one generating plant to the next looking for ways to improve performance and profitability.

Their main yardstick for evaluating performance is heat rate, which is essentially fuel consumption divided by electrical output. To determine this, they bring in a lot of specialized instrumentation which they install. They take readings from these instruments, make their adjustments, and then remove it all when they’re done. Using conventional wired networks, they used to spend a lot of time sorting through signal dropouts caused by wiring problems before they got any useful readings.

When such failures occurred, excessive troubleshooting time and a high level of expertise were required to determine the root cause. As the team got used to saying, “Technicians install the wiring, and engineers troubleshoot it.” To address these concerns, the team adopted WirelessHART for instruments temporarily installed to perform gas turbine and cooling tower tests. By avoiding much of the complex wiring normally required for this type of temporary installation, the team estimates it saves 15 to 40 percent of setup time.

The team isn’t able to use WirelessHART for all their instrumentation simply due to device availability limits, but they would if they could. Avoiding the wiring problems has improved their ability to get tests done far more quickly.

Modern wireless technology allows the team to perform more than 100 tests and performance evaluations each year. The experience gained adds to an extensive database of documenting past performance challenges and solutions. According to the power plant performance team, it would not be able to perform as much testing with conventional wiring due to the high amount of labor, installation, troubleshooting, and decommissioning time needed for the wired infrastructure.

So, think about other ways to use wireless field devices. Here are some ideas for ways to get more from a WirelessHART network:

Temporary installations, just like our subject company learned
Mobile installations, such as an equipment skid that has to move around
Instruments requiring frequent relocation, such as moving a Rosemount X-well Temperature Transmitter from one measurement point to another
Adding adapters, such as the Emerson Wireless 775 THUM Adapter, to conventional instruments
Adding instruments even when existing I/O slots are all filled.

How are you using WirelessHART in your plant? Let’s hear about creative ways you’ve extended its capabilities. You can tell 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.

New Monitoring and Analytics Tools Improve Plant Performance

Brian Joe — Mon, 17 Feb 2020 20:14:23 GMT

Where is your company at in its digital transformation journey? Just starting, well along, or still waiting?

One reason to begin or make progress on such a journey is improving diagnostics by digitizing the process.

Case in point: Electric utilities are coming to grips with industry changes as generation capacity shifts. The need to run the remaining plants differently can impact efficiency if operators and the reliability team don’t know what’s happening. Fortunately, while these changes are disruptive, the tools to solve the problems and smooth over new ways of working have never been better. Has your company implemented any of these tools yet? If not, here’s how.

The IIoT makes the process of monitoring equipment condition and performance far easier and less expensive than ever before. That’s the topic of our article in the December 2019 issue of Power, New Monitoring and Analytics Tools Improve Plant Performance. Here’s a key point:

Analytics platforms designed to crunch and sort data gathered via smart sensors are providing users with the ability to apply predictive diagnostics to equipment and assets. More data is available now than ever before, largely due to new sensors supported by WirelessHART transmitters. It is now possible to collect continuous condition and performance data on large populations of assets (Figure 1) thanks to lower hardware and installation costs.

There are WirelessHART instruments to monitor most of the equipment and key assets common to a generating plant, including CCGT units, which are often under-instrumented. Here are some possibilities:

Pumps, motors, and gearboxes
Heat recovery steam generators (HRSGs)
Cooling towers
Heat exchangers

Data gathered needs to move to the next stage—analytics—which can be done automatically using platforms like Plantweb Insight:

Once processed, engineers can use data to predict problems before they affect operations. This allows maintenance, reliability, safety, plant engineering, and other departments to make quicker, more-intelligent decisions about their operations. With these educated decisions come cost savings, cost avoidances, improved maintenance and reliability, better safety, and improved heat rate.

The article goes into more detail, so give it a read and ask yourself a few questions:

Do you know where the “bad actors” are in your plant? What are the components and equipment taking up more than its share of maintenance time and cost?
What were the causes of your most recent outages? Do you have a good handle on where those problems originated? How you can keep the same thing from happening again?

Let’s hear about your situation. How far have you gone in automating data collection and analysis? You can tell 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 all sorts of industries around the world. Look for the Power and Essential Asset Monitoring Communities, plus other specialty areas for opportunities to provide input, suggestions, and answers.

VIDEO: Best Practice Approach to Optimizing Control Through IIoT

Rich Carpenter — Tue, 28 Jan 2020 21:07:56 GMT

Plant Operators are feeling more pressure than ever before to utilize IIoT, but many do not know where to get started or where digitalization utilized.

In this video, I will discuss the Emerson best practice approach for optimization strategy and how to achieve better control through heightened project & equipment visibility, while improving services you already have in place.

www.youtube.com/watch

Would IIoT help you solve a visible issue? Unsure where to start? Start a conversation or ask a question in the Emerson Exchange 365 community by replying below.

Maximize Production by Monitoring Erosion

daviesjj — Thu, 09 Jan 2020 20:08:22 GMT

There’s an old saying in manufacturing that suggests if you’re machinery and equipment don’t break down from time to time, you aren’t pushing production hard enough.

Some maintenance people may take issue with exactly how such a concept is implemented, but it’s true. To maximize production, you have to know exactly how hard you can push without causing so many outages they outweigh the gains. Let’s apply that to oil refineries and other chemical processing where one of the wear items is piping itself. Eventually after you push enough product through the pipes, they lose metal from the inside due to erosion and corrosion. The pipe wall becomes thinner, and if not caught in time, fails and releases the contents. Naturally, the harder the plant runs, the faster this happens.

Understanding when piping has reached such a critical point and where it is happening is the challenge. However, there are answers, which is the topic of my article in the December 2019 issue of Oil & Gas Engineering, Maximize Production by Monitoring Erosion. It examines the tools and techniques for determining how fast piping is losing its metal and eventually integrity. Without hard data on equipment condition, it is difficult to optimize production and determine the best use of CAPEX dollars.

Fixed equipment integrity is one example where cohesive, high-quality and timely data is often lacking. On the one hand, the corrosive effect of produced fluids and the erosive impact of produced sand particles in oil & gas-produced streams is well understood. On the other, information about the impact of these corrosive or erosive materials on actual asset integrity is often absent. The solution is to monitor continuously for corrosion and erosion and use this information to improve operating efficiency.

Such a program has two parts: First, look for the causes of accelerated metal loss, and a primary culprit is sand in the liquid. Second, monitor the actual wall thickness continuously in real time. Let’s look at how these two parts work together in concert.

Sand entrained in oil & gas streams poses significant risk to production equipment because it is moving at high velocities inside fixed equipment and can eat away metal piping and equipment from the inside, with an effect like sand blasting. This erosion occurs inside of piping and equipment, making its effects extremely difficult to detect via exterior inspection. However, modern measurement techniques can detect both entrained sand and its impact on asset integrity. Acoustic sand detectors identify the presence of sand in the production flow by listening for the sound of solid particles hitting the piping’s insides. With careful calibration, the sand entrainment rate can be estimated.

This monitoring calls for Emerson’s Roxar™ SAM Acoustic Sand Monitor, which can turn sand noise into actionable data. Understanding how much sand is in the product is very valuable information, but it doesn’t indicate how much damage has been done. We also need the second part of the answer, wall thickness monitoring.

Now imagine the transformational effect of automated sensors permanently attached to strategic points in the infrastructure to take continuous, robust measurements of remaining pipe wall thickness. The sensors use wireless technology to send gathered data for analysis at a central, safe and convenient offshore or onshore location. Operators would gain immediate insight into what’s happening with fixed equipment at any given time, with no need for guesswork.

Emerson’s Rosemount™ Wireless Permasense ET210 Corrosion and Erosion Monitoring System provides ongoing visibility of corrosion and erosion trends in real-time, using data supplied by unique and non-intrusive ultrasonic sensors that continuously measure pipe thickness.

Putting these two solutions together—and comparing factors such as production rate, sand content, and other variables against metal loss over time—presents a far more complete picture of what is happening, providing operators with the ability to identify cause-and-effect relationships.

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 Oil & Gas Group, and other specialty areas for suggestions and answers.

Augmented Reality Application for Safety Critical Element Maintenance & Risk Communication for operation

Peddy Nesa — Thu, 26 Dec 2019 14:13:52 GMT

Dear All,

I am looking for industrial practice oil and gas which related to SCE (Safety Critical Element) maintenance and risk communication using Augmented Reality in order to improve preventive maintenance effectiveness, comply with SCE performance standard and acceptance criteria, and also better risk communication during SCE abnormal condtion to assist new field operator and maintenance personnel.

Is there any body hands on with these case?

Thanks in advance for the sharing

Peddy Nesa

VIDEO: Enhance Safety with Wireless Gas Detection

Ryan Bowlds, P.E. — Thu, 19 Dec 2019 22:40:09 GMT

Safety is our customers’ number one concern. In industries where toxic and combustible gases are present, flame & gas detection products help safeguard critical assets and maintain a profitable operation. In this video, I talk about how Emerson has recently released a new platform for wirelessly detecting the presence of toxic and combustible gases in areas that were previously too difficult or costly to monitor. By eliminating many of the costs associated with wiring, setup, and maintenance of the Rosemount 928 Wireless Gas Monitor and 628 Universal Gas Sensor provide a reliable solution for remote installation.

www.youtube.com/watch

Please share your experiences or ask us questions about improving the safety of your facility with wireless gas monitoring by replying below.