Refining Blog

Non-Intrusive Measurements: Closing Critical Gaps Without Shutdowns

2026-04-27T15:58:36Z

The challenge for many refiners is whether the installation risk, outage dependency, and ongoing maintenance burden can be justified. When those barriers remain in place, uncertainty forces conservative decisions. Non-intrusive measurement directly targets those constraints by allowing new measurement points to be added without cutting into piping, breaking containment, or waiting for outages.

The post Non-Intrusive Measurements: Closing Critical Gaps Without Shutdowns appeared first on the Emerson Automation Experts blog.

Catching the Weak Signals: Improving Refinery Safety Through Better Visibility

2026-04-10T15:02:10Z

Most major refinery incidents do not start with dramatic failures. They start with small, unremarkable changes that go unnoticed until it is too late.

The post Catching the Weak Signals: Improving Refinery Safety Through Better Visibility appeared first on the Emerson Automation Experts blog.

Precisely Measuring Watercut in Crude Oil

2025-10-29T13:00:02Z

In a Fluid Handling Pro article, “Achieving Precision Measurement with the Roxar Watercut Meter from Emerson” Kelda Dinsdale shares the story of a Chinese refinery that needed to monitor and analyze the crude oil and water going into the desalter unit.

The post Precisely Measuring Watercut in Crude Oil appeared first on the Emerson Automation Experts blog.

Enhancing Accuracy and Reliability in Gas Measurement: A Case Study on DP Flow Meters

2025-07-09T01:00:12Z

In the dynamic world of industrial gas supply, accuracy and reliability are paramount. We recently explored a transformative solution implemented by a leading gas plant provider that delivered remarkable results for a Taiwanese multinational company. This company supplies industrial gases to various sectors, including medical, chemical, and electronic fabrication, and operates in over eighty countries.

The Application

Gas plants are critical to ensuring the consistent supply of essential gases like nitrogen, oxygen, hydrogen, helium, and carbon dioxide. Accurate flow measurement within these plants is vital not only for optimizing operations but also for maintaining safety and compliance standards, especially in high-purity applications like semiconductor manufacturing.

Figure 1. An exterior view of the gas plant, like the customer’s site, that would supply gases to the main plant from the utility wing of the plant.

The Challenge

The company offers customized onsite gas generation solutions that deliver bulk volumes of industrial gases, such as nitrogen, oxygen, and hydrogen, to a variety of industries. These offerings include full-service installation, operation, and maintenance of the gas supply system.

The end user required a highly accurate flow meter capable of maintaining precision across varying flow rates. The main priorities were to achieve accurate readings in both high and low flow conditions, reduce shutdown frequency, and increase overall production uptime. They also needed a consistent flowmeter type that could be applied uniformly throughout the production line.

At the time, the facility was using diaphragm gas meters and thermal mass flow meters, both of which produced unsatisfactory results. Thermal mass flow meters required gas-specific calibration and were only suitable for clean, non-abrasive media with known thermal properties. These devices also came with high capital expenditures. Diaphragm gas meters, which use mechanical components, required regular maintenance and were generally limited to smaller pipes operating at low flow rates and pressures.

As a result, the plant experienced significant downtime due to the need for annual audits and calibrations. These limitations prevented the implementation of predictive maintenance strategies and restricted the range and flexibility of their flow measurement process.

Figure 2. Working Principle of the Thermal Mass Flowmeters (left) and the Diaphragm Gas Meters (right) that resulted in poor accuracies during audited calibrations.

The Solution

To address these issues, Emerson provided a solution using a combination of the Rosemount™ 3051SMV MultiVariable™ Transmitter and the Rosemount™ 3051SFC Compact Orifice Flow Meter, designed to deliver high flow measurement accuracy, including temperature-compensated flow. This setup supported predictive maintenance strategies by eliminating the need for frequent manual calibration and costly annual gas audits.

Optimized for variable flow applications across both high and low flow conditions, the solution also removed the need to stack transmitters, simplifying the installation. The 3051SMV was utilized as a pay meter for billing transactions between the gas plant and the end user. As a mass flowmeter, it offered online calibration capabilities—performed annually without interrupting the gas supply—and proved to be a cost-effective and scalable choice.

Each gas line in the facility transported different gases—including nitrogen (N₂), oxygen (O₂), hydrogen (H₂), helium (He), and carbon dioxide (CO₂)—across various pipe sizes. This complexity previously required frequent calibration and equipment replacement. In high-purity applications like semiconductor manufacturing, any disassembly of the flow meter also triggered an N₂ purging process, adding further cost and downtime.

The Rosemount™ 3051S MultiVariable™ Transmitter simplified operations by enabling measurement of multiple variables using a single model number. This not only reduced the need for stacked transmitters and extra wiring, but also minimized pipe penetrations and connection systems—key for cost-efficiency and maintaining gas purity.

Depending on process needs, the system could be equipped with a compact orifice plate, 4-hole conditioning orifice plate, or averaging pitot tube. These options provided reliable measurements across closed-loop control, general process monitoring, and custody transfer applications. Emerson’s time-tested orifice technologies followed well-established manufacturing standards and were proven to perform under a wide range of installation and process conditions.

Following the success of the initial deployment, the customer expanded implementation, replacing 40 to 60 sets of older metering systems with Emerson’s solution over the course of two to three years. This upgrade—initiated by one of the largest semiconductor plants in Taiwan—marked a full-scale shift from conventional gas meters to Emerson’s 1595 DP Flow technology and Rosemount™ 3051S MultiVariable™ Transmitter.

The Results

The implementation resulted in significantly improved measurement accuracy across both high and low flow conditions. The customer achieved mass flow rate accuracy of up to ±1.0%, which enabled online calibration for the pay meter application—removing the need for costly shutdowns during annual audits.

With enhanced data accuracy and sensor stability, the solution contributed to better decision-making and helped prevent unplanned downtime. By enabling predictive maintenance and streamlining gas flow operations, the Emerson system supported the customer’s goals for safety, reliability, and continuous plant uptime.

Customer Experience

“The Rosemount™ 3051S MultiVariable™ Transmitter, fully assembled with the 1595 Conditioning Orifice Plate, helped improve operational certainty across key parameters such as safety and reliability—while enabling us to move toward predictive maintenance.” – A large Semiconductor Plant in Taiwan

Conclusion

This case study highlights how Emerson’s advanced flow measurement solutions can address the complex challenges faced by industrial gas providers. By deploying the Rosemount™ 3051S MultiVariable™ Transmitter and 1595 Conditioning Orifice Plate, the customer streamlined operations, improved billing accuracy, and moved confidently toward predictive maintenance. For industries where gas purity, process stability, and cost efficiency are mission-critical, Emerson’s technologies offer a proven path forward.

For more information, visit:

The post Enhancing Accuracy and Reliability in Gas Measurement: A Case Study on DP Flow Meters appeared first on the Emerson Automation Experts blog.

Forging a New Value Chain: Advanced Solutions for Carbon Dioxide Measurement in CCUS

2025-06-13T17:36:21Z

Over the last century and more, a few industries have developed large-scale integrated production and distribution systems, covering the span from source to final consumer. Oil and gas are the most obvious, covering all aspects of industrial, commercial, and consumer applications. We’ve come to call these systems value chains. With the growth of environmental concerns, we can now add carbon dioxide to this list as its capture is now being tied to its utilization and storage (CCUS).

While we may think of carbon dioxide as waste and therefore valueless, many reasons are emerging for why we must reevaluate it in the same terms of more valuable products, calling for volume and custody transfer measurements on a par with oil and gas. But measuring carbon dioxide is complex because it can take a variety of forms. Solving this challenge is the topic of my article in Global Hydrogen Review, Developing Infrastructure for CCUS.

For decades, carbon dioxide has been widely used in industries such as oil and gas (especially for enhanced oil recovery), food and beverage (for carbonation and preservation), manufacturing (for welding and chemical production), agriculture (for greenhouse enrichment), and fire suppression. However, in most of these applications, carbon dioxide emissions were treated as a byproduct rather than a significant environmental issue. But, as compared to these existing industrial uses, the CCUS industry brings completely new challenges and a higher level of complexity.

While the article does touch on how and where carbon dioxide can be sequestered or utilized, it focuses more on the gas’s unique properties and the challenges they pose for accurate measurement during pipeline transport.

Flow measurement can be challenging because of a unique physical property of carbon dioxide, namely that all three states – gas, liquid, and supercritical – occur at typical industrial operating temperatures ranging from -40 to +50 °C, and at operating pressures ranging from 100 – 200 bar. This is very different from hydrogen and methane, for example, each of which only transforms to liquid from gas phase at significantly lower temperatures, ranging from -160 to -255 °C.

The article goes into more detail on the range of conditions that might be encountered under various pipeline configurations. What’s really worth reviewing is how Emerson’s Micro Motion Coriolis Mass Flow Meters use their mass measuring capability to see through those confusing phase shifts. Moreover, this capability has been tested independently by DNV to certify Micro Motion ELITE™ Flow Meters for custody transfer use:

As the DNV findings summarised: “Emerson’s Micro Motion ELITE Coriolis flow meters are OIML R 137 certified for measurement of gases including carbon dioxide with accuracy class 1.0. The performance of the Coriolis flow meters in this joint industry project (JIP) further illustrates the capabilities of the Emerson Coriolis flow meter to generate accurate mass measurement even under challenging operating conditions.” They can thus be deployed to support the critical carbon dioxide capture, transport, and sequestration processes, helping to build a reliable infrastructure.

These are the first flow meters thus certified in this application, ensuring they will be critical as the new carbon dioxide value chain is forged.

Consultation with Emerson experts can help companies active in the CCUS value chain pick the right product from the range of available meters for their applications, with assurance that these meters will perform as designed, while complying with all applicable industry standards.

For more information, visit Emerson’s Carbon Capture Process pages at Emerson.com. You can also connect and interact with other engineers in the Oil & Gas and Chemical Processing Groups at the Emerson Exchange 365 community.

The post Forging a New Value Chain: Advanced Solutions for Carbon Dioxide Measurement in CCUS appeared first on the Emerson Automation Experts blog.

Emerson Provides the Only Flow Measurement Solution for Carbon Dioxide

2025-06-13T17:36:21Z

For decades, carbon dioxide has been widely used in industries such as oil and gas (especially for enhanced oil recovery), food and beverage (for carbonation and preservation), manufacturing (for welding and chemical production), agriculture (for greenhouse enrichment), and fire suppression. However, in most of these applications, carbon dioxide emissions were treated as a byproduct rather than a significant environmental issue. But, as compared to these existing industrial uses, the CCUS industry brings completely new challenges and a higher level of complexity.

The article goes into more detail as to how and where carbon dioxide may be sequestered or utilized, but it spends more time on its peculiar characteristics and how they make measurement difficult when transferred via pipeline.

Flow measurement can be challenging because of a unique physical property of carbon dioxide, namely that all three states – gas, liquid, and supercritical – occur at typical industrial operating temperatures ranging from -40 to +50 °C, and at operating pressures ranging from 100 – 200 bar. This is very different from hydrogen and methane, for example, each of which only transforms to liquid from gas phase at significantly lower temperatures, ranging from -160 to -255 °C.

Again, the article goes into more detail on the range of conditions that might be encountered under various pipeline configurations. What’s really worth reviewing is how Emerson’s Micro Motion Coriolis Mass Flow Meters use their mass measuring capability to see through those confusing phase shifts. Moreover, this capability has been tested independently by DNV to certify Micro Motion ELITE Flow Meters for custody transfer use:

As the DNV findings summarised: “Emerson Elite Coriolis flow meters are OIML R 137 certified for measurement of gases including carbon dioxide with accuracy class 1.0. The performance of the Coriolis flow meters in this joint industry project (JIP) further illustrates the capabilities of the Emerson Coriolis flow meter to generate accurate mass measurement even under challenging operating conditions.” They can thus be deployed to support the critical carbon dioxide capture, transport, and sequestration processes, helping to build a reliable infrastructure.

These are the first flow meters thus certified in this application, ensuring they will be critical as the new carbon dioxide value chain is forged.

Consultation with Emerson experts can help companies active in the CCUS value chain pick the right product from the range of available meters for their applications, with assurances that these meters will perform as designed, while complying with all applicable industry standards.

The post Emerson Provides the Only Flow Measurement Solution for Carbon Dioxide appeared first on the Emerson Automation Experts blog.

Effectively Managing Opportunity Crude-Caused Corrosion Podcast

2025-05-29T13:00:47Z

At the Emerson Exchange 2025 Conference, Emerson’s Marcelo Carugo and Doug Cooper joined Hydrocarbon Processing Magazine podcast host Lee Nichols to discuss advanced digital technologies to combat corrosion.

Visit the Gulf Podcast Network Hydrocarbon Processing “The Main Column” for the May 22, 2025, podcast recording titled Live from Emerson Exchange: Advancing digital technologies to combat corrosion.

Transcript

Lee: So hello everyone. I want to welcome you all to this latest episode. My name is Lee Nichols and I’m going to be your host. Now this is a very special episode as we are live from Emerson Exchange. And today’s episode is all about corrosion.

Now to discuss this extremely important subject, which affects, I think, nearly every industry around the world, we have two very special SMEs from Emerson joining us today: Marcelo Carugo and Doug Cooper. How are you guys doing today?

Marcelo, Doug: Great. Great.

Lee: Well listen I know this conference y’all are very very busy so I really appreciate y’all’s time today. So before we dive into some of the questions I have about corrosion can you provide the listeners a little bit more information about yourself and your roles with Emerson?

Marcelo: Certainly. Thank you Lee for having us here. Very much appreciated the opportunity. Marcelo Carugo. I am Vice President for Industry Solution Consulting and Customer Success at Emerson. I’ve been with Emerson 27 years.

Doug: And I’m Doug Cooper. I am the Director of Product Management for our APM business unit within Emerson. And I’ve been with Aspen Tech slash Emerson for five years now.

Lee: Excellent. So today we’re talking all about corrosion. So my quick question to start off this conversation is can you put corrosion monitoring into context for the listeners? So in other words, how big of a problem is corrosion in refineries today?

Marcelo: Certainly. If we look at the refineries with the utilization of opportunity crudes that has been more and more pervasive on the past five, ten years we can see a larger impact of corrosion because of these different crudes and the switching of crudes. When we look at refineries we can see refineries in different parts of the world that will switch 100 crudes a year.

Maybe the largest ones would switch 300 crudes a year. And this different variety of crudes provide different complexity of mechanisms of attacks for corrosion that are different. And there is an opportunity of making more money using these crudes but also provides the challenge of how to manage the corrosion. And of course if there is a corrosion incident in a refinery in most cases it could be a safety, will produce a safety incident as well. So we want to avoid that at all costs.

Managing corrosion has always been a situation with manual inspections. Now with technology we can actually improve a lot how we can manage that and actually capture a lot of the value and profitability that the refinery can have.

Lee: Yeah, well that’s actually a great segue into my next question is so what are some of the traditional ways that refiners are managing their corrosion, and you know that then leads to where are they falling short?

Doug: Yeah, I can handle that one. So Lee, what most of the refiners have done in the past is they’ve done manual inspections using you know UT thickness or X-ray and they’ll take a corrosion measurement at a period of time, six months, a year, and then they’ll graph those out and they’ll look at the you know the corrosion rates based on you know those two points or eventually you get three, four, five points and that’s how you get your corrosion rates. But in that middle of that six months, they really don’t have any idea what’s gone on if they switched crude slates or different things in the middle. They could have had corrosion rates that are varying, so it’s very much backward-looking. I know now that this is how much wall thickness I have left, this is how much remaining useful life I have in the pipe, but I don’t know what’s gone on in between.

So Emerson has taken some steps to help out with that with our Rosemont Permasense sensors. And so with the Permasense sensors, they’re wireless sensors, they’re online, and they’re able to take corrosion measurements typically once a day. So now they have a really good idea real time of what’s going on from a corrosion standpoint and how maybe different crude slates affect that. And you know if they’ve changed some process conditions, they can start to see some of those things. But again it’s all still looking in the rearview mirror. I know it’s happening with corrosion and you know what companies are now asking for is more of how do I manage that? Is there a way to manage the corrosion? Not just you know go with what’s happening out there. So that’s what we’re looking to move forward to.

Lee: Excellent. And so then I kind of want to swing back to the topic of opportunity crudes. So y’all have a joint session here at Emerson Exchange this week and y’all are talking about leveraging the benefits of opportunity crudes. Now you mentioned, of course, it can be economically beneficial, but can you talk a little bit more about the benefits of opportunity crudes?

Marcelo: Yes, certainly. So when you process an opportunity crude, you have different areas that you can leverage the value of the molecule, right? And there is a great opportunity of processing more opportunity crudes if you can manage all the challenges that you have through corrosion and the processing. But also availability of the units is important. And for that, the integrity management of the units is really a key area. And also addressing the maintenance costs, right? So when we look at all these three aspects of the profitability of the refinery, we identify for a typical 200,000-250,000 barrel refinery, an opportunity of about $10 million.

Lee: Okay. Wow. Then let’s talk about combating corrosion. So can y’all talk a little bit more about why a new corrosion management solution is needed then to help combat corrosion?

Doug: Yeah. So what we want to do is help these operating companies understand the causes of corrosion, whether it be some of these different crude slates, process type conditions, and if they can understand when we’re starting to see the beginning of a higher corrosion rate, what’s going on, they oftentimes, you know, from a process standpoint, can make some slight corrections and put them back down into acceptable corrosion levels.

And on the flip side of things, you know, with what Marcelo talked about earlier, with the different crude slates, with some of the models we’re going to be building with this, they will have a better understanding of the corrosion rates they could see if they do decide to go down that road. And then again, we can play with some of the process conditions to help them stay in more manageable corrosion rate areas of where they want to be going forward.

Lee: Okay. Yeah. And then that kind of then leads me to my next question, because I want to talk about the solution, which I know features Emerson products and then AspenTech software. So can y’all talk a little bit more about those key features?

Marcelo: Yeah, certainly. We are leveraging on this new development, the full stack of Emerson and AspenTech. So we are tackling the instrumentation. And certainly is what Dark mentioned about the thickness sensors. But also we are looking at the data around the unit, right? So if we are talking, for example, a crude unit, we are looking at the crude data, we are looking at the lab data, we are looking at the process data. And we combine all these with machine learning and AI from AspenTech to be able to leverage the new technologies and being able to get all these new insights that you can have, right?

Because something that probably the listeners could relate to, you buy crudes nowadays and they come with a crude assay, but the properties of the crude that you have are not normally what the assay says, right? So you have to take that into consideration. And then typically the refineries will have blends of these crudes. So how that will behave and what will be the corrosion rate impact is a time concept that we have to manage there, right? And this tool provides you the ability to manage this on a day-to-day basis.

Lee: And so let’s talk real-world case studies because I know so many people in this industry say that sounds great, benefits are great, does it work? So I’m wondering if y’all have any type of examples from some initial customers who’ve already started to see the success with this solution.

Marcelo: Yes, of course. So we have been working with a selected group of customers on a pre-alpha version of the tool. And we were looking at different use cases with them. And they found value in, I would say, three different areas.

So in many cases, you have in a refinery, you have a particular corrosion incident, and you have to go back and look at what is the root cause of this. And it’s something that is time-consuming. In some cases, it could take weeks. Some worse cases could take a few months to identify that, right? And with this tool, we are able to provide you insights in what the root cause has been and what were the main contributors to that incident in minutes. Who were the main contributors to that incidence in minutes. So that’s one of the things that we found this group of refiners were able to appreciate.

The other one has been for a certain scenario, to do some scenario analysis. If we are going to run a certain crude and if we want to run it for certain operating conditions to get the more value of the molecule. What will be the envelope that we can run? What are going to be the conditions for that? So that scenario analysis has been another good value that refiners appreciated.

And finally, when you’re looking at the operating conditions from the point of view of corrosion, you have also an operating window that it will operate. But because of the different aspects we talked before, this window is not static, it’s dynamic. So this tool also provides you what is the dynamic operating window at any time. So you can optimize from the point of view of minimizing corrosion.

Lee: Oh wow, okay. Excellent. And then it’s incredible technology. So yeah, and I know how busy you guys are, but I mean, is there any closing thoughts before we let you all go?

Doug: Yeah, we have one. So Marcelo talked about pre-alpha, but we’re getting ready to have an alpha where we’re doing some testing. And we would love to have the input of operating companies. We’ve put our heads together and we think we’ve got what is gonna be a great solution, but we greatly value the voice of the customer, right? And we’d love to have them participate in this.

So we are actually gonna be kicking off some alpha testing of this new solution. And we’d love to have input and have loved to participate. So if anyone would like to participate, they can reach out to Marcelo or myself. Marcelo’s email is marcelo.carugo@emerson.com and I’m douglas.cooper@aspentech.com. And we’ll get you able to be signed up and participate and provide some feedback and help us shape how this tool is gonna take shape.

Lee: Excellent. We’ll put y’all’s email address in the show notes.

Marcelo: Perfect. Thank you very much, Lee.

Lee: Excellent. Well, listen, I know how busy y’all are at this event. It’s a huge event. I’ve learned actually a lot already and I think it’s only been about a day and a half. So it’s been really good. So again, really want to thank y’all for carving out a couple minutes to talk to us about this important topic. And of course, as always, we want to thank all of you for listening to this very special episode live from Emerson Exchange.

-End of transcript-

The post Effectively Managing Opportunity Crude-Caused Corrosion Podcast appeared first on the Emerson Automation Experts blog.

Versatile, Wide-Ranging Watercut Measurements

2025-05-08T20:46:11Z

Watercut meters, used in oil & gas production, pipeline distribution, and refinery applications, are advanced and designed to measure the percentage of water in oil flow precisely to help you maximize oil production and reduce operating costs.

In this quick 2-minute YouTube video, What Is the Measuring Range of the Roxar™ Watercut Meter?, Emerson’s Fiona Butters highlights the enhanced versatility of the Roxar Watercut Meter with the TopCut feature, expanding its range from 0-50% to an impressive 0-100% water cut, perfect for applications requiring a broader range.

Transcript

The Roxar Watercut Meter generally operates as a low-cut meter, which is where the water cut ranges from 0 to 15%. Or a high cut meter where the water-cut range is 15 to 50%. The meter sensor resonates on a broad frequency range. On a water range of 0 to 50%, the resonating frequency span is doubled compared to the required frequency span needed for measuring 0 to 15% range.

In the 0 to 50% range, the oil contains water droplets. In the range from 50 to 100%, the fluid is water-continuous, which means there are oil droplets in the water.

The signal that is emitted to the sensor is absorbed by the water if the fluid is water-continuous and does not provide a sufficient return signal. Our meter will only measure water in oil-continuous flow unless we upgrade to the top-cut function and use a density input from either a Coriolis or densitometer.

In instances where the oil density changes, such as in well testing, the use of the auto-zero feature and the density input from a Coriolis or densitometer will allow the Roxar Watercut Meter to use the live measured density for optimum accuracy.

To learn more about the Roxar water cut meter and how you can leverage your operations, please visit us at Emerson.com/Roxar or contact your local representative through the Ask the Expert option.

The post Versatile, Wide-Ranging Watercut Measurements appeared first on the Emerson Automation Experts blog.

The Growing Sophistication of Instrumentation Makes In-House Servicing Less Practical. Here’s an Alternative.

2025-04-16T14:40:13Z

I work with a lot of engineers and other mechanically minded people, but I don’t know many that work on their own cars. Maybe an oil change here or there, but the sophistication of today’s engines and internal networks makes DIY work so impractical that it really must be left to specialists. The same idea applies to much of the technology used in process manufacturing today. Think of the differences between a mechanical pressure gauge compared to our Rosemount 3051S Pressure Transmitter, and you get the idea.

Where does that leave our customers? Are there still armies of instrument techs and specialized maintenance people left in chemical plants and refineries in the real world? While there may be some, the likely answer is no, or at least far too few. Our solution for this conundrum is the topic of my article in Processing magazine, Employing Predictive Maintenance as a Service to Improve Operations. This is the first installment of a three-part series, so more will follow looking at specific areas in greater depth.

The situation leaves a company considering what areas are critical enough to keep in-house, and what should, or must be farmed out.

A facility will likely buy services for commoditized tasks such as electric motor repair, or it will have highly sophisticated equipment, such as an analyzer, serviced externally. Internal maintenance efforts are usually reserved for specialized process equipment where both critical skills and timing are paramount. For most companies, the list of maintenance tasks kept in house has declined.

Where does your company fit into this picture? If the control room loses view of a critical process variable, is it due to the instrument transmitter, the device-level network, the automation host system, or something else altogether? How quickly can you solve the problem? Do you have the necessary people in the plant ready to respond? Was that instrument sending out a diagnostic warning that something was wrong before it went dark?

The personnel to perform basic maintenance functions are universally available, and the skills necessary are largely the same at any process plant or facility. However, in today’s plants, there is required maintenance at a higher level to keep sophisticated instrumentation, device-level networks and automation host systems operating flawlessly to maintain optimized processes. This convergence of operational technology (OT) and informational technology (IT) also presents unique challenges in process plants.

OK, that presents a major problem because such highly skilled people are hard to find and retain in most plants. Your local motor shop and even many traditional maintenance contractors can’t handle it either. What’s the solution?

Maintenance-for-hire will fix things that are broken. Some sophisticated providers may even use predictive techniques in strategic situations, but a true lifecycle services provider will help their client’s teams work safer, smarter and faster by enabling them to make better decisions. Plant personnel gain efficiency, productivity and clear insight thanks to the services and solutions provided by partner firms.

So, what does that look like?

Emerson Measurement Lifecycle Service’s approach for instrumentation assets provide end users with an outcome-focused, service-based solution. Relationships are built by transforming the way maintenance, calibration and repair tasks are handled — with a goal of delivering sustainability, reliability and uptime. These services help process manufacturers safely optimize facility performance, monitor overall equipment effectiveness (OEE) for those assets and develop strategies to fulfill their business goals.

The article goes into more detail, so give it a full reading. It explains how these services work, and what our client companies have come to expect.

Utilizing efficiency tools such as automation, continuous monitoring, optimization, and performance services provide for timely, data-driven decision making when it comes to maintenance and repair, while ensuring safety and reliability remain intact. Our services keep facilities operating safely, consistently, and economically, improving asset reliability and return on investment.

Visit the Emerson Measurement Instrumentation Lifecycle Services page at Emerson.com.

The post The Growing Sophistication of Instrumentation Makes In-House Servicing Less Practical. Here’s an Alternative. appeared first on the Emerson Automation Experts blog.

Optimizing the Hydrotreatment Process in Sustainable Aviation Fuel Production

2025-04-09T13:00:02Z

The global push to reduce greenhouse gas emissions, particularly within the aviation sector, is driving a rapid expansion of sustainable aviation fuel (SAF) production. SAF or biojet is a renewable fuel approved for commercial airlines and can be blended up to 50% with conventional jet fuel. However, SAF production presents unique operational challenges associated with feedstock variability and conversion processes.

In an article published in Hydrocarbon Processing magazine, Lara Petrishchev and Julie Valentine share measurement instrumentation strategies for navigating the complexities of biofuel production, especially within the hydrotreatment process unit of the refining process.

SAF Production Challenges

SAF is produced through lipid conversion processes, utilizing renewable feedstocks rich in oil, such as used cooking oil, oil-bearing plants like rapeseed and soybeans, and tallow. These feedstocks undergo pretreatment to eliminate contaminants that can harm reactor catalysts and to break them down into consistent intermediates that feed the hydrotreating and isomerization reactors.

Despite the pretreatment process of bio-based feedstocks, SAF feedstocks present unique challenges:
• They tend to be more corrosive, leading to operational issues.
• Their variability adds another layer of complexity.

In addition, the SAF refining process demands significantly more hydrogen (H₂) and operates at elevated pressures and temperatures.

The hydrotreatment unit is the heart of the plant where fatty acid feedstocks are converted into hydrocarbons, so maximizing yields depends on optimizing reactor operations to handle feedstock variability and meet quality standards.

Improving Process Control

To optimize the operation of the hydrotreatment and isomerization unit, strategically deploying measurement sensors is critical to improving visibility into process conditions for better decision-making.

Critical bed temperature transmitters (left) should utilize dual sensors and detect sensor drift. Remote electronic pressure transmitters measuring catalyst bed differential pressure (dP) (right) will require gold-plated diaphragms for H2 service. Both must be SIL-2 or SIL-3 capable.

Controlling Highly Exothermic Reactions:

- Temperature transmitters with advanced diagnostics and dual hot backup capabilities are vital for monitoring reactor temperatures and ensuring process safety.
- Quad vortex flow meters provide redundant flow measurements for hydrogen treat gas, purge streams, and reactor recycle flow, preventing temperature excursions. With a two-out-of-three (2oo3) voting SIL-3 configuration, they enhance both safety and process control.
- Differential pressure transmitters monitor pressure drop across reactor beds, indicating potential catalyst fouling.

Monitoring Yields and Catalyst Deactivation Rate:

- Coriolis meters are crucial for the main feed, hydrogen, and product streams. Their ability to measure both mass flow and density enables accurate mass balance data for yield monitoring and catalyst evaluation.

Corrosion Monitoring:

Wireless corrosion and erosion sensors can be placed in strategic areas throughout the process to detect and monitor corrosion. Their wireless design allows them to be added or moved easily to meet service needs.

- Wireless ultrasonic corrosion sensors provide real-time indication of metal loss and monitoring of pipe wall thickness. This helps ensure equipment integrity given the variable and often more corrosive nature of renewable feedstocks. Check out this article for more insights on managing corrosion risk in biofuels processing.

Hydrogen Purity Monitoring

- Continuous gas analyzers and gas chromatographs play a critical role in monitoring the purity of hydrogen streams for optimal conversion rates. They also track H₂S in the recycle stream for better reaction control.

Energy Efficiency & Emissions

- Continuous gas analyzers and Continuous Emissions Monitoring Systems (CEMS) provide real-time data to quantify greenhouse gas emissions.
- Real-time monitoring of flows, temperatures, and pressures of both process and transfer fluids in heat exchangers provides early detection of equipment fouling. The measurements optimize heat transfer and significantly reduce energy waste and emissions.

Simplifying Regulatory Reporting

- Automated level and flow metering instrumentation with onboard diagnostics facilitates accurate fluid transfer measurements and reporting, ensuring compliance with regulations. This includes custody chain documentation, invoices, transportation, and audit trails critical to securing government subsidies.

Read the article for more information on how careful selection of measurement instrumentation and control strategies can help refiners optimize SAF production, meet stringent regulatory requirements, and advance sustainability initiatives.

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Turning Carbon Capture into a Revenue Stream

2025-02-20T14:30:12Z

Imagine that tomorrow, someone comes to your plant and says, “I want to buy all the carbon dioxide that you can produce.” We know there are indeed applications where carbon dioxide is a feedstock, and injection for enhanced oil recovery is another possible use, but the list is short.

Let’s consider the idea from a different angle. Say the visitor offers, “I want to buy all the carbon dioxide that you don’t produce.” What might this mean? It is a much more realistic suggestion, and how it could produce revenue for your company is the subject of my article that was published in both Hydrocarbon Processing and Gas Processing & LNG, in both instances titled Monetizing Carbon Capture, Transport, and Storage.

Carbon capture projects are proliferating rapidly, mostly in North America and Europe. But how do these shift from being a cost to producing revenue?

In some areas around the world, governing bodies have instituted limitations on CO₂ emissions. Companies can emit up to the established limits, and regulators intend to incentivize reductions and/or penalize them when limits are exceeded. Some regions have chosen to incentivize reductions. For example, a long-standing cement plant will have a permit to release some thousands of tons per year of CO₂ equivalent. If a plant can reduce its output below that figure, it may have an opportunity to sell the excess allowable emissions to another facility that is unable to stay within its limit.

There’s the opportunity, and the idea is getting more common. If your carbon capture system brings you below your limit, you can sell the leftover permits. Environmental goals are still reached because the overall total is not exceeded. So, what is necessary to facilitate this in areas where such programs are operating?

The company buying the credits has a seemingly simple request, but in practice this can be a difficult question to answer: How do we prove to the relevant regulatory agency and/or credit markets that these are legitimate credits? The burden of proof is on the seller. If money is changing hands, or if emissions credits are accepted, the relevant agencies and parties will want auditable proof of what has transpired.

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This is not as difficult as it sounds. If your company, as the seller, has thoroughly instrumented carbon capture units with effective automation, gathering the required data should be manageable. If your company isn’t sure about how to do this, we can help. Emerson has a wide range of instrumentation ideal for these applications, and a few are discussed specifically in the article:

These tools can ensure effective control and monitoring of carbon capture, making it possible to document all transactions and satisfy the requirements of every permit transfer, similar to the methodology now used for custody transfer of oil and gas products.

Companies should be exploring the practicality of reducing their emissions by using CCS strategies, along with calculating the possible value of selling their excess reduction as a new income stream. Partnering with a single provider able to support all aspects of such a program can shorten the development time and ensure successful project executions.

For more information, visit our Optimizing Carbon Capture pages at Emerson.com. You can also connect and interact with other engineers in the Oil & Gas Groups at the Emerson Exchange 365 community.

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Simplifying Natural Gas Analysis

2025-02-17T14:30:34Z

Gas chromatographs (GCs) separate and analyze the various components in a mixture. Natural gas analysis applications often use these to identify the hydrocarbon components of varying carbon chain lengths. For instance, C6 refers to a carbon molecule consisting of six carbon atoms.

The Rosemount 470XA Gas Chromatograph is a compact, economical, and reliable solution that simplifies natural gas analysis in fiscal and custody transfer applications. The wealth of data in these intelligent analytical instruments that can be integrated at the edge or into cloud-based applications for global accessibility is part of Emerson’s Boundless Automation vision to help manufacturers and producers drive more efficient and sustainable operations.

It provides accurate C6+ BTU/CV measurement that is fully traceable to international standards and doesn’t require a shelter for most environments, lowering the total cost of ownership.

With an oven design based on the industry-proven Rosemount 770XA Gas Chromatograph, it offers flexible gas path configurations suitable for applications in renewable natural gas/biomethane and hydrogen markets.

Visit the Rosemount 470XA Gas Chromatograph page for more about its specifications and capabilities.

Transcript

Throughout the natural gas industry, gas chromatographs are utilized during custody transfer events. When the gas changes ownership between sellers and buyers to measure the component content of the gas and calculate its energy value, usually expressed in BTU or calories, as well as the Wobbe index of the gas.

The Emerson Rosemount XA family of gas chromatographs have been mainstays in traditional natural gas custody transfer applications for the past decade. As natural gas sources have evolved to include sustainable and renewable sources, the need for greater flexibility and gas chromatograph capability has accelerated.

Emerson’s Rosemount 470XA GC provides the standardized C6+ BTU/CV measurement for which the Rosemount line of gas chromatographs has been historically known while also providing the platform for expanding our based GC line to new emerging applications and engineered-to-order solutions.

With an oven design based on our top-of-the-line Rosemount 770XA natural gas chromatograph, the 470XA has the flexibility to support new gas measurement capabilities within the carbon capture and storage market. Hydrogen measurements for hydrogen injection in natural gas, low BTU gas applications like biogas generation and transmission, and custody transfer of renewable natural gas products.

The Rosemount 470XA delivers the long-term stability and expected performance with the serviceability support and MON2020 interface of the XA series product line. As an industry leader in the natural gas space, Emerson has more than half a century’s experience designing and manufacturing gas chromatographs and thousands of units installed globally.

With the introduction of the 470XA, we’re providing more options for sustainability activities in the natural gas marketplace while maintaining the same level of accuracy, reliability, durability, and performance expected.

-End of transcript-

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Micro Motion™︎ Coriolis Flow Meters Are Now Easier to Select and Install, Providing Even More Value to Chemical Industry End Users

2024-12-11T20:01:02Z

One aspect of consumer electronics that we all appreciate is how designers have worked to make things easier to use. It wasn’t that long ago when adding some peripheral device to a computer called for fiddling with drivers and configuration, whereas today many devices are plug and play. The same also happens with industrial equipment, and we can use Micro Motion Coriolis mass flow meters as an example.

Coriolis flow meters have some very strategic and unique capabilities that make them ideal for a variety of complex measurement applications, but taking advantage of all these features can be challenging. Emerson has worked to ease these issues, as explained in this recent article in Chemical Engineering, Coriolis Flowmeters: Insights for Selection and Upgrade.

Coriolis meters are one of the few flow meter types that can directly measure the mass flow of either gases, liquids, or slurries. They also simultaneously directly measure density and temperature, providing three vitally important measurements within a single meter. Most importantly, the mass-flow measurement remains accurate despite process variation, allowing production units to consistently close the loop on process mass balances and optimize production.

These capabilities are all needed, and even more features are now available. For starters, the range of sensor designs has increased to reduce size, and to support specialized application and configuration options. A great option for chemical manufacturers is the recently released Micro Motion G-Series Coriolis Flow and Density Meter, an ultracompact and lightweight solution offering simple installation and integration. Additionally, a range of Micro Motion Coriolis sensors is available with characteristics that cater to different needs and applications. Micro Motion Flow Meters

Transmitters also have new, valuable options for the chemical industry. For instance, the Micro Motion 4700 Coriolis Transmitter offers a compact C1D1 (Zone 1) housing, scalability from 1-3 output channels, Bluetooth® Technology, and retrofitting to existing Micro Motion sensors.

The article goes into more detail on Coriolis additional new features, but a chat with one of our application engineers will be very informative.

If faced with the need to specify a new Coriolis flow meter or upgrade an existing sensor, users should fully understand the assortment of sensor and transmitter options that have recently become available. Coriolis meters have always been a premier flow-measurement device, but the latest technological advances make these meters even more capable and affordable.

You can also connect and interact with other engineers in the Downstream Hydrocarbon and Chemical Processing Groups at the Emerson Exchange 365 community.

The post Micro Motion™ Coriolis Flow Meters Are Now Easier to Select and Install, Providing Even More Value to Chemical Industry End Users appeared first on the Emerson Automation Experts blog.

Navigating Corrosion Hotspots in Amine Units: A Guide for Refineries and Gas Processing Plants

2024-08-14T13:48:26Z

Amine units are critical components in refineries and gas processing plants, removing acidic contaminants like H2S and CO2 from process streams. However, these units are particularly vulnerable to corrosion, which can lead to costly shutdowns and safety risks. Let’s explore the key corrosion hotspots in amine units:

Absorber Towers:

Prone to wet acid gas corrosion, especially in the vapor space at the bottom.
Water vapor condensation can lead to carbonic acid formation, accelerating corrosion rates.

Flash Tanks:

Sediment accumulation increases the risk of under-deposit corrosion.
Inlet nozzles are susceptible to erosion from iron-based corrosion products.

Lean/Rich Amine Heat Exchangers:

Two-phase flow can cause rapid thinning of metal surfaces and excessive vibration.
Non-wetted surfaces are vulnerable to carbonic acid attack in CO2-dominant systems.

Regenerator Inlets:

Two-phase feed formation can lead to erosion of the vessel wall opposite the feed point.
Liquid droplet carryover in the vapor stream can cause downstream issues.

Reboiler Systems:

High-velocity vapor flow and turbulence can accelerate erosion on metal surfaces.
Proper pressure management is crucial to control two-phase flow.

Overhead Condenser and Accumulator:

High shear rates, turbulence, and steam velocities contribute to corrosion and erosion.
Impinging vapors can erode equipment walls and remove protective passivation layers.

Throughout the Entire System:

Heat-stable salts accumulate and cause significant corrosion across the entire unit.
Entrained corrosion products can lead to operational issues like foaming and fouling.

Monitoring these hotspots is crucial for maintaining the integrity of amine units and preventing unplanned shutdowns. Traditional inspection methods, however, often fall short due to their periodic nature and the need for process interruptions.

This is where Emerson’s advanced corrosion monitoring solutions come into play. Their non-intrusive sensors, such as the Rosemount™ Wireless Permasense ET210 Corrosion and Erosion Monitoring System, offer continuous, real-time corrosion data without compromising system integrity. These sensors can be installed at multiple locations throughout the amine unit, even in hazardous areas, providing comprehensive coverage of all corrosion hotspots.

Emerson’s monitoring systems enable engineers to correlate corrosion rates with process conditions, optimize operations, and make data-driven maintenance decisions. The flexibility in sensor mounting options – including straps, magnetic mounts and studs – allows for easy installation on various equipment types and metallurgies.

By implementing Emerson’s corrosion monitoring solutions, operators can significantly improve their amine unit management. This proactive approach leads to safer operations, extended equipment life, and substantial cost savings by preventing unplanned outages and optimizing maintenance schedules.

Learn more at Emerson.com/Corrosion-Erosion

The post Navigating Corrosion Hotspots in Amine Units: A Guide for Refineries and Gas Processing Plants appeared first on the Emerson Automation Experts blog.

Navigating Corrosion Hotspots in Amine Units: A Guide for Refineries and Gas Processing Plants

2024-08-14T13:48:26Z

Absorber Towers:

Prone to wet acid gas corrosion, especially in the vapor space at the bottom.
Water vapor condensation can lead to carbonic acid formation, accelerating corrosion rates.

Flash Tanks:

Sediment accumulation increases the risk of under-deposit corrosion.
Inlet nozzles are susceptible to erosion from iron-based corrosion products.

Lean/Rich Amine Heat Exchangers:

Two-phase flow can cause rapid thinning of metal surfaces and excessive vibration.
Non-wetted surfaces are vulnerable to carbonic acid attack in CO2-dominant systems.

Regenerator Inlets:

Two-phase feed formation can lead to erosion of the vessel wall opposite the feed point.
Liquid droplet carryover in the vapor stream can cause downstream issues.

Reboiler Systems:

High-velocity vapor flow and turbulence can accelerate erosion on metal surfaces.
Proper pressure management is crucial to control two-phase flow.

Overhead Condenser and Accumulator:

High shear rates, turbulence, and steam velocities contribute to corrosion and erosion.
Impinging vapors can erode equipment walls and remove protective passivation layers.

Throughout the Entire System:

Heat-stable salts accumulate and cause significant corrosion across the entire unit.
Entrained corrosion products can lead to operational issues like foaming and fouling.

Learn more at Emerson.com/Corrosion-Erosion

The post Navigating Corrosion Hotspots in Amine Units: A Guide for Refineries and Gas Processing Plants appeared first on the Emerson Automation Experts blog.