Refining Blog

Solving Level Measurement Challenges for Chemical and Petrochemical Plants

Jim Cahill — Fri, 10 Sep 2021 20:21:41 GMT

According to OSHA, the chemical industry has one of the most stringent safety regulations. Regular inspections, servicing, and maintenance work are required due to the intense stress that is often placed on the equipment because of the exposure to very aggressive substances and extreme high temperatures and pressures. Depending on the size and type of plants and operations concerned, maintenance often involves a complete shutdown, however, maintenance and servicing operations in localized production areas are common.

In recent times, chemical plants are adapting new recommendations and incorporating newer processes to meet the highest safety guidelines prescribed across industries. Faced with many harsh process conditions such as low pH environments, boiling liquids and extreme pressures at a typical site, companies are turning to automation and upgrading their activities from simplified manual operations to more sophisticated equipment, driving greater production efficiency and safety management practices.

Figure1: Typical applications in Petrochemical and Chemical Plants

Frequency Modulated Continuous Waves (FMCW) versus Pulsed Systems

Pulsed systems

Pulsed radar systems which is a Non-Contacting Radar type using an antenna, measure level based on the time-of-flight principle and use a method called time expansion to convert extremely short time delay to a slower timescale. The surface echo is built up of tens of thousands of short radar pulses emitted from an antenna positioned at the tank top, directly towards the process material below. These pulses are reflected from the surface of the material back to the transmitter. The transmitter measures the time delay between the transmitted and received echo
signal, and the on-board microprocessor calculates the distance to the process media surface using the following formula: distance = (speed of light x time delay) /2. Once the transmitter is programmed with the reference gauge height of the application— usually the distance from the flange face to the bottom of the tank or chamber—the level measurement is then calculated by the microprocessor.

FMCW technology

Instead of measuring time, Non-Contacting Radar using FMCW technology transmits a radar signal with a frequency, increasing over time to create a signal sweep. After the signal is reflected by the process media surface, the echo is picked up by the antenna. As the transmitted signal varies in frequency, the echo has a slightly different frequency compared to the signal being transmitted at that moment. The difference between these frequencies is directly proportional to the echo delay (i.e., the distance from the transmitter to the process media surface), which enables the level to be accurately measured. An advantage of this technique is that the process variable information is in the frequency domain instead of the amplitude modulated (AM) or time difference domain, which allows more accurate signal conversion. This is the same advantage that FM radio has over AM radio. Most tank noise sources are in the amplitude domain and thus FM signal processing can ignore them, and accuracy is not affected.

Smart Diagnostics & Real Time Intelligence

Two of the major challenges customers in the Chemical and Petrochemical industry face are:

No data to act on before failure of instrument
Limited data for troubleshooting

We have developed two specific features to assist in solving these issues. The first is the Signal Quality Metrics (SQM). By looking at the Signal to Noise margin, our device enables predictive maintenance before the instrument encounters error due to failure such as build up on the antenna or the probe.

To solve the issue of limited data for troubleshooting, we have developed a unique 7-day data historian, to allow users to revisit and check echo curve at the time of event in an on-board memory. The data collected by the Rosemount 5408 and 5408:SIS are compliant with NAMUR NE 107 Field Diagnostics for standardized device diagnostic information.

Figure 2a (left): Rosemount 5408 Non-Contacting Radar Historian Dashboard showing active (colored) and inactive (grey) failures and alerts; Figure 2b (right): Rosemount 5408 Non-Contacting Radar installed on a Chemical Tank

One Stop Level Solution

We will be discussing many more features around the Level portfolio in the presentation including topics of Functional Safety for Level Measurement including Proof Testing, Interface measurement and Reactor Level measurement specific.

Figure 3: The Rosemount Level Solution Portfolio including all the technologies from Guided Wave Radars, Non-Contacting Radars, Custody Grade High Precision Non-Contacting Radars, and Point Level Switches & Level Detectors

Join us at Emerson Exchange Asia Pacific, coming on October 26-28, 2021. Register for the event via our webpage, Emerson Exchange Asia Pacific.

The post Solving Level Measurement Challenges for Chemical and Petrochemical Plants appeared first on the Emerson Automation Experts blog.

Avoid Taking a Successful Reliability Program for Granted by Improving Its Use

Jim Cahill — Mon, 23 Aug 2021 19:06:38 GMT

Success must be supported so it can be sustained. As Chris Jensen and H.P. Slater discuss in an article in the July issue of Process Heating, this line of thinking is no less true in predictive maintenance (PdM) than in anything else.

Some companies are impressed with the initial savings that PdM programs generate through improved production and lower maintenance costs, but

New PdM programs typically identify many issues. As these issues are remedied, the resulting improvements allow the reliability team to claim significant cost avoidance. As the program matures, however, the number of new issues discovered is reduced due to the assets operating in a healthier state. Defects have been eliminated, operational problems have been rectified and equipment “infant-mortality” issues have been addressed.

So, when problems are reduced and improvements are realized, how do companies often respond?

This type of reduction can result in staffing cutbacks, the elimination of program assets and extensions of inspection frequencies. The results of these reductions may not be readily evident to management; they typically will only notice the expense reductions. As time goes on, however, when asset failures result in adverse effects on operations, management may decide the PdM program is ineffective. The thinking may go, “We have a PdM program, but it did not notify us of an issue on a critical asset, and we had the failure anyway” — all while forgetting the reductions in PdM investment.

Some of the change in management’s mindset is unavoidable, so those responsible for the PdM program must be ready to evolve to the next stage while the company is still enjoying initial success. The program must become more driven by condition monitoring, using a higher degree of automation to measure asset condition and performance.

In the article the authors cite an example of a pump that seems to be performing adequately, but really isn’t up to par. The right condition monitoring sensors and data analysis systems can report the deficiency.

A condition-monitoring program focuses on knowing the status and health of all assets and, ultimately, system performance and health. Paying attention to asset health allows reliability teams to ascertain, as early in the detection process as possible, if an item of concern is developing. In the case of the underperforming pump, a condition-monitoring system will alert plant personnel that the pump is operating but with degraded performance.

The article goes into more depth as to how to justify and plan the first steps of this evolution, along with the kinds of successes it can generate. Ultimately, the goal is to build a program able to measure overall plant health, with an emphasis identifying issue early on before they become apparent to operators, and long before they cause loss of equipment life or threatens production.

Emerson’s condition monitoring solutions are tuned to your applications and the criticality of your machines, and they deliver data you can count on for accurate diagnosis of machinery condition. Here’s a video on condition monitoring for production assets to help guide your thinking.

Visit the Condition Monitoring pages at Emerson.com. You can also connect and interact with other engineers in the Oil & Gas, Chemical, and Life Science Groups at the Emerson Exchange 365 community.

The post Avoid Taking a Successful Reliability Program for Granted by Improving Its Use appeared first on the Emerson Automation Experts blog.

Gaining Real-Time Insights to Improve Operational Performance

Jim Cahill — Fri, 13 Aug 2021 16:15:47 GMT

Since we’re nearing the end of vacation season, how many of you appreciate the digital transformation that has occurred over the years where you can quickly find the optimum transportation, lodging, meals, entertainment, etc. to make the most of your vacation. And how much faster can you do all these things than was possible even a few years ago?

Manufacturers and producers are also pursuing digital transformation initiatives. A common roadblock is data siloed in different locations which slows down the ability to make informed decisions quickly to improve performance. In this quick 4-minute video, Gaining Insight into Operational Performance to Optimize Production, Emerson’s Juan Panama explains how the Plantweb digital ecosystem breaks down data siloes so facilities can run harder, more reliably and safer. Data is collected and broken down to provide real-time insights into process status, facility health and to increase reliability.

Juan opens highlighting a few of the many sources of data including process data, monitoring data, lab and analyzer data. The Industrial Internet of Things technologies has enabled wireless sensors to be added to manage the overall health of the plant and equipment. The key is to break down the siloes where this data exists and bring them together to perform comprehensive analysis with operational analytics software to provide real-time insights into how the process is performing.

He describes Plantweb Optics Data Lake as a solution for an enterprise data store with flexibility for both structured and unstructured data, and contextualization to associate data with logical units. For example, in a refinery with changing crude oil slates, the challenge has been how maximize profitability, balance opportunity crudes with premium crudes, and continue to operate safely and reliably.

With Plantweb Optics Analytics, analysis can be performed on a broad spectrum of data to provide insights on the best way to achieve these objectives. Juan demonstrates this with an example showing a refinery site overview. With the data siloes broken down, the analytics can determine a corrosivity index. This index can help keep down corrosion levels to avoid unplanned outages and in the case of turnarounds, get back up and running much quicker by only having to inspect what is identified as an issue.

Juan shows a high corrosivity index alert in a fluid catalytic cracker (FCC) unit. The index is calculated from pressures, temperatures, and intrusive corrosion measurements to measure the pH of the fluid and combining with non-intrusive corrosion measurement data that measures the real-time piping wall thickness. This index is a leading indicator of overall plant health. Having this data available for real-time analysis and creating this leading indicator enables plant staff to run the facility harder yet safely and reliably.

Visit the Plantweb Optics Platform section on Emerson.com for more on these technologies and solutions to drive improvements in safety, reliability and overall efficiency.

The post Gaining Real-Time Insights to Improve Operational Performance appeared first on the Emerson Automation Experts blog.

Analyzing Combustion – Looking for Leftover Oxygen

Jim Cahill — Mon, 19 Jul 2021 16:22:33 GMT

In an automation.com article, Emerson’s Jesse Sumstad and Neil Widmer explain how accurate measurement of excess oxygen in flue gas can be used to improve combustion control.

These days, industrial facilities operating combustion processes face multiple concerns, including:

Burner efficiency
Fuel costs
Emission restrictions
Public perception of a company’s carbon footprint and overall environmental responsibility.

All these factors drive the importance of effective combustion control and overall efficiency. The best way to determine combustion efficiency is to analyze what’s going out the stack, starting with residual oxygen. This is not a new idea and many installations have some technology to measure oxygen, but, many operators don’t fully understand what the reading means.

Clearing up this frequent misunderstanding is a key point of our article at automation.com in June, Understanding Oxygen Measurement in Flue Gas Streams. We look at two common measurement technologies, and explain why they can give significantly different measurements in the same application. The reason is, there are effectively two kinds of residual oxygen, and differentiating them requires thinking about combustion itself.

Combustion is a chemical reaction between the fuel and oxygen (O₂) and is therefore subject to basic stoichiometric factors. The correct number of O₂ molecules must be available to react with the corresponding number of fuel molecules. Air flow imbalance in either direction is problematic. If there is insufficient air (below the stoichiometric requirement, or fuel-rich combustion), unburned fuel goes out the stack. This wastes fuel, creates emissions and hazardous air pollutants. It also creates a potential safety issue should enough fuel subsequently mix with O₂ and ignite.

So far, so good, this part is clear. But we know no reaction is 100%, so there will invariably be some unburned fuel. Therefore, the amount of O₂ in the stack is a mix of O₂ that should have burned to match the amount of fuel, and that which is truly in excess of the stoichiometric requirement.

If there is too much air (above the stoichiometric requirement, resulting in fuel-lean combustion), efficiency is reduced due to energy wasted heating the unnecessary volume of air. This is inescapable to some extent since approximately 80% of air is nitrogen, but excess air is less problematic for efficiency and safer for operation, although nitrogen oxides (NOx) emissions can increase with increasing excess air. For most combustors there is an ideal excess air to achieve good combustion, low emissions and high efficiency.

All that to say, the most important measurement is the true unnecessary volume, but some analyzer technologies can’t tell the difference without a second analyzer to measure the amount of unburned fuel. However, Emerson’s Rosemount 6888A In Situ Oxygen Analyzer provides the desired reading because it automatically consumes any O₂ in excess of the stoichiometric requirement.

The Rosemount proprietary zirconia sensor has a particular characteristic to avoid this problem. Flue gas, including both leftover O₂ and any unburned fuel, flows into the sensor. Given the high temperature and high surface area of the platinum beads, combustion of any unburned fuel and leftover O₂ is completed through catalytic-enhanced oxidation. Since all combustion is completed in the sensor, any O₂ remaining in the sensor represents excess O₂, which is different than the total O₂ in the flue gas if unburned fuel is present. Because excess O₂ is directly related to excess air, operators can control air flow in real-time to maintain the ideal amount of excess O₂.

When operators know the true excess O₂ level as delivered by the Rosemount 6888A In Situ Oxygen Analyzer, they can make adjustments to run at the optimum excess O₂ percentage. Visit the Combustion Gas Analyzers pages at Emerson.com for more information. You can also connect and interact with other engineers in the Oil & Gas, Chemical, Onsite Utilities, and Power Generation Groups at the Emerson Exchange 365 community.

The post Analyzing Combustion – Looking for Leftover Oxygen appeared first on the Emerson Automation Experts blog.

Monitoring for Corrosion in Refineries

Jim Cahill — Mon, 21 Jun 2021 20:12:56 GMT

Rosemount Wireless Corrosion & Erosion Monitoring

Processing crude oil into fuels and other products requires addressing the corrosive contaminants that this crude can contain. Effective corrosion monitoring and management can help avoid potentially catastrophic safety and environmental incidents.

In a Hydrocarbon Engineering article, A Fine Balance, Emerson’s Jake Davies describes ways to address the corrosion and erosion that can wear away piping, tanks, vessels and valves in the refining process.

Jake opens highlighting 3 major challenges. The first is that corrosive contaminants are present and sometimes in greater amounts with lower quality crude oils. Second:

…the equipment in a refinery and even within a single unit typically differs by age, quality, and design. For example, a crude unit was originally conceived and built to process specific amounts of crude oil on a daily basis from a specific range of sources. Piping metallurgy and schedule reflect the expected service life under the anticipated conditions.

Finally, refineries operate today with less people with less experience. Manual monitoring is harder to periodically perform. Jake describes how to address corrosion and erosion from both a capital expenditure (CAPEX) and operational expenditure (OPEX) perspective.

From a CAPEX perspective, refiners can invest:

…in plant or unit upgrades, replacing the most critical piping and equipment with higher-grade alloys and heavier schedules able to withstand corrosive feedstocks and process conditions over a long service life. This is obviously an expensive solution and takes time to implement.

From an OPEX perspective, refiners can attempt:

…to reduce the metal loss caused by corrosive process fluids by adding corrosion inhibitor additives. This can be very effective but presents its own challenges. First, the inhibitor must be matched to the corrosive agent(s) in the crude and the concentration. An ineffective combination does not solve anything and wastes the additive, so the effectiveness must be optimised and reevaluated whenever there is a feedstock source change or other process adjustment.

He highlights several ways to monitor for the impact of corrosion including coupons, electrical resistance (ER), electrochemical and ultrasonic thickness measurement. Coupons:

…using the same material as the piping, can be inserted into the process fluid to mimic the pipe wall. Monitoring metal loss from the coupon manually over time can be extrapolated to the whole system.

ER and electrochemical probes:

…indicate the presence of corrosive agents in the process fluid in real-time. Installing these requires process penetrations, but the data is highly useful since it provides immediate feedback as to the corrosiveness of a new batch of crude, and therefore warns when conditions are conducive to high metal loss.

Non-intrusive Ultrasonic Thickness (UT) sensors:

…mounted in strategic positions to measure metal thickness continuously. UT sensors that use the latest signal processing techniques are capable of repeatability of around 10 μm (0.4 mils), making it possible to detect even very small changes in metal thickness over time. Data can be collected and historised to monitor metal loss for root cause analysis and predictive maintenance.

Read the article for Jake’s perspectives on the best combination of technologies for data collection and analysis, on , and on taking a systemic approach to corrosion monitoring, on data presentation and on value creation opportunities to deliver the necessary ROI for investments in these technologies.

Visit the Rosemount Wireless Corrosion & Erosion Monitoring section on Emerson.com for more on the these technologies and applications for better-informed operational decision making and safer, more sustainable operations.

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ISAConnect Members-Only Peer Communities

Jim Cahill — Tue, 15 Jun 2021 12:57:49 GMT

The International Society of Automation (ISA) is growing nice online communities in their members-only ISAConnect section of the website. One of the active groups, Chemical and Petroleum Industries Division (ChemPID), is led by Emerson’s David Lee. David is an Operator Performance Senior Consultant. ChemPID’s mission is:

…to contribute to the professional involved in the processing of chemicals, petrochemicals, petroleum, and natural gas. From raw materials to products ChemPID strives to advance best practices in: Safety, Environmental, Production Efficiency, Operations, Process Control, and Automation.

Currently, there are more than 3200 members in this online community. Reasons for joining ChemPID are:

Leadership Opportunities – The opportunity to improve your personal leadership skill level and participate on panel discussions as well as serving as a session developer for ChemPID conferences and symposia.
Technical Writing – Reviewing papers or writing articles for the ChemPID newsletter or Web pages.
Networking – Increase your visibility in the ChemPID industry to benefit both you and your employer and the opportunity to have a positive impact on the industry.
Valuable Information Resources – In addition to the above, ChemPID membership supplies: Two to three comprehensive industry newsletters per year featuring articles and papers from the ChemPID Members and symposium participants. Access to the ChemPID website that provides industry technical papers, web seminars, and a list serve of industry peers.

You can follow technical discussions in the forum area that are tagged with Chemical. Some other industry & expertise tags include Oil and Gas, Power and Energy, Mining and Metals, Instrumentation, Connectivity and Cybersecurity, Water and Wastewater, Process Safety, Smart Manufacturing, and Pharmaceutical.

David shared some upcoming ChemPID events this month. These include:

You’ll find many active Emerson experts (see advanced search and add Emerson to company name field) out in these forums. For example, Jonas Berge is quite active.

These online ISAConnect communities, available to ISA members, can help connect you with fellow experts and help you improve your career advancement. And don’t forget to vote this month for the ISA officers if you are a current ISA member.

The post ISAConnect Members-Only Peer Communities appeared first on the Emerson Automation Experts blog.

Controlling Corrosion as Fossil Fuels Become Increasingly Sour

Jim Cahill — Mon, 14 Jun 2021 16:00:47 GMT

One question that various friends ask when they learn we work with many oil industry companies is, “Are we running out of oil?” The answer is no. There’s still plenty of oil and gas, but new sources are more difficult to extract, and the crude is often lower quality. Low-quality in this context generally means sour, based on sulfur content. The biggest problem with sour oil is its corrosiveness—it destroys equipment, costing industry trillions of dollars every year, and it has caused countless loss-of-containment incidents globally.

Beginning back in 1975, the National Association of Corrosion Engineers (NACE) published a group of standards for dealing with corrosive products, including critical effects of material selection. These standards have been updated and expanded over the years and are now widely used throughout the chemical and oil & gas industries. They offer guidance on material selection for piping, valves, and vessels. We wrote an article reviewing these standards in the February issue of Oil & Gas Engineering, showing how corrosion can have significant negative consequences.

The presence of sulfides in oil and gas creates additional challenges down the value chain until the sweetening process, which is used to remove sulfides from sour gas or oil. Hydrogen sulfide (H₂S) in process media presents significant risks to hydrocarbon facilities in terms of cost, equipment damage, and harm to personnel.

The importance of these standards and the whole issue of corrosion is only getting worse:

The oil and gas industry has shifted more of its production to fields where sulfur and other corrosive agents are more abundant. A 4 parts per million (PPM) concentration of hydrogen sulfide in air under standard temperature and pressure is often referred to as sour, and crude oil with more than 0.5% sulfur is called sour crude. According to the International Energy Agency (IEA), about 43% of the world’s natural gas reserves are sour. The gas reserves in the Middle East, for example, are estimated to be about 60% sour.

Anyone working in an upstream oil & gas facility, a refinery, or many types of chemical plants, needs to understand these standards and how to apply them. The article is an excellent basic resource. There is also a webinar titled Wouldn’t it be NACE?, where we share what end users and vendors need to know from these standards, how they apply to the hydrocarbon value chain today, and the importance of reducing corrosion in severe applications in such facilities across the world.

Emerson’s portfolio of valves, actuators, and regulators offers an enormous range of configurations and materials designed to withstand corrosive crudes and other chemicals. What’s happening in your facility? Are you using effective strategies for managing corrosion? Visit the Valves, Actuators, and Regulators pages at Emerson.com to learn more about how you can improve your existing efforts.

Also, visit the Corrosion and Erosion Monitoring pages for products and techniques for measuring the effects of corrosion in real time. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.

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Deliver better control, reliability, and safety in today’s demanding steam operations with Rosemount 8800 MultiVariable Vortex Flow Meter

Jim Cahill — Thu, 06 May 2021 18:03:00 GMT

Vortex flow measurement is uniquely adaptive when it comes to handling difficult applications. By virtue of its science, utilizing the von Kármán effect, these instruments are accurate across a wide operating range and effective at withstanding high process pressures and temperatures. In this post, we’re highlighting the latest in our 8800 Flow Meter product portfolio – the MultiVariable Vortex Flow Meter. Designed with superheated steam applications in mind, we’ve combined proven temperature and flow measurement technology into one powerful device. With this MultiVariable meter option, we can deliver better control, reliability, and safety in today’s demanding steam operations.

Let’s Talk Steam

We’ve talked before about the unique challenges of measuring steam applications and how Vortex flow meters are particularly well-suited for measuring saturated and superheated steam applications. Another challenge with steam applications is how its density can fluctuate depending on the temperatures and pressures of a process. Volumetric flow rates are a measurement of the space a liquid occupies as it is flowing. For steam, volumetric flow rates don’t represent the most accurate measurement of its flow because of this constantly shifting density. A more accurate representation for steam applications is mass flow rate, the measurement of the mass of the fluid as it flows. Operators benefit from flow meters with multivariable capabilities that can provide them with compensated mass flow readings as process temperatures and pressures change.

Our MultiVariable Vortex Flow Meter has an integrated temperature sensor within the meter body. This thermowell is incorporated inside of the vortex meter’s shedder bar to capture process temperatures without adding additional leak points to the all-welded meter body design. It eliminates the need to install and maintain a separate measurement point for temperature. We can now account for fluctuations in density to provide operators with a highly accurate mass flow rate in demanding steam applications.

The Problems with Integrated Pressure Sensors

We’ve engineered our MultiVariable Vortex Flow Meter to measure temperature along with volumetric flow rates to deliver the most reliable flow measurements for steam applications possible. We’ve designed it to pair with a separate transmitter to receive pressure data via a HART pressure device like the industry-leading Rosemount 3051S Pressure Transmitter. Together, these instruments ensure a trustworthy compensated mass flow measurement.

When pressure sensors are integrated into the vortex flow meter along with temperature sensors, additional processing piping and meter body penetration is needed to support the integrated pressure sensor. This exposes the end user to the potential of plugging and clogging of process piping and safety risks of additional leak points. It also makes new vortex installation more complicated, risking improper process sealing, damage to the seal, and escaping fluids when the flange connection is opened. If the pressure module is integrated directly into the meter body, the electronics of the pressure sensor are more prone to failure from high temperatures due to the close proximity to the process piping. We’ve found that these meter designs introduce too much potential for installation issues, measurement errors, and inconsistency overall.

The Advantages of Installing a Rosemount 8800 MultiVariable Vortex Flow Meter

Emerson’s MultiVariable flow meter utilizes external pressure measurement to take full advantage of the benefits of vortex technology. The all-casted, all-welded body eliminates ports, crevices, and gaskets for clog-free functionality. Real-time temperatures and pressure measurements are measured or received by the electronics inside the transmitter to perform the calculations necessary for compensated flow measurement. The integrated removable temperature sensor is isolated from the process and separate from the vortex sensor which facilitates independent verification or replacement of each sensor without breaking the process seal.

Today’s steam operations need more reliable instrumentation to meet the demands of high temperatures and pressures while maintaining the highest levels of plant safety. We’ve engineered our solution to meet these critical needs and provide the insights our customers need to continuously improve their optimization and energy balance strategies. Learn more, link.

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How to Streamline Complex Natural Gas Analysis, Reduce Cost and Footprint Using New Gas Chromatographs

Jim Cahill — Tue, 02 Mar 2021 14:42:11 GMT

Reliable natural gas quality analysis is critical to minimizing safety, operability and financial problems across the value chain. Variability in gas quality can create a variety of challenges for large-scale users, particularly for use as a fuel for gas turbines or sophisticated fired heaters, where the BTU rating (calorific value) is critical. For gas turbines, the Wobbe index indicates additional characteristics affecting its suitability as a fuel. For some users, contaminants can be just as important.

To meet gas quality measurement requirements, operators have traditionally used multiple gas analyzers with different technologies, or relied on conventional air-bath oven gas chromatographs which are complex large platforms unsuitable for field-installation without elaborate analyzer shelters, adding significant capital and operating costs.

In a Gas Processing and LNG magazine article, Jason and I explain how to streamline complex gas quality analysis while saving costs and footprint using new field-deployable gas chromatographs (GCs) that deliver a single, compact and cost-effective solution to report on the contents of natural gas supplies.

Today’s gas chromatographs are no longer one-size-fits-all. They are designed to fit the list of components that operators specify for their routine applications. For example, a basic GC can typically handle a fixed proportion of hydrocarbon components as outlined by Gas Processors Association (GPA) Midstream Standard 2261.

For many applications, such as when a facility operating a gas turbine must ensure that the pipeline supply meets essential Wobbe Index requirements, this methodology is often sufficient.

For users needing to quantify additional components, including heavier hydrocarbons for critical dew points, a C9+ GC uses a double-column/detector set in a two-stage configuration. Quantifying contaminants, such as sulfur in its various forms is a different matter. Traditionally, total sulfur measurements were typically made using separate, dedicated analyzers employing different technologies. Another option relied on a flame photometric detector (FPD) in conjunction with the conventional air-bath oven gas chromatographs which are too large and expensive for field use.

With traditional analyzer technologies, measuring quantitative values of BTU content, hydrocarbon dewpoint, total sulfur, and hydrogen sulfide have often required up to four analyzers using different analysis methods. However, the development of:

…a micro-flame photometric detector (µFPD) makes it possible to include this technology on smaller, less-expensive, transmitter-style GCs. It is now possible to enclose the hardware for all measurement stages in a single, airless oven, minimizing size and complexity.

Leveraging the micro-flame photometric detector, Emerson’s Rosemount 700XA GC, an explosion-proof analyzer designed for in-situ or close-to-tap field mounting, can measure hydrogen sulfide (H₂S), energy content, hydrocarbon dewpoint, as well as trace-level speciation and quantification of total sulfur compounds in a single compact solution. ATEX/IECEX safety rated, the Rosemount 700XA GC doesn’t require a shelter, even in Class 1, Division 1 areas, thereby eliminating the need for air purged enclosures.

To avoid the cost of using multiple analyzers for complex natural gas analysis, read the article for ways to use the Rosemount 700XA GC for extended gas composition analysis, streamlining measurements, and saving CAPEX and footprint. The article also describes how automated processing and remote connectivity of the Rosemount 700XA reduce the need for specialized training.

Visit the Gas Analysis pages at Emerson.com for more on technologies and solutions for quality and content evaluation. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.

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Empowering the Workforce in a Digitally Transformed Refinery

Jim Cahill — Tue, 16 Feb 2021 20:18:09 GMT

It’s no secret that the refining business has a people problem. Like manufacturers in other industries who rely heavily on technology to stay competitive, refiners understand the need to transform their operations by extending the Industrial Internet of Things and other digital innovations across a wider range of possibilities. What many managers struggle with is how to integrate these changes into their workforce while considering the impacts they will have on their broader organizations over time.

While challenges certainly exist, the truth is that only when refiners link their technology and personnel strategies to their business objectives, embed expertise into their work processes, and optimize their operations in every way they can using real-time data does achieving Top Quartile performance become possible.

This article, How refiners can empower a digitally transformed workforce, focuses on strategies and technologies available to enable refiners to better manage the skills shortage—primarily due to increasingly complex operations and a generation of seasoned experts retiring—and will include the following essential competencies that are critical to helping workers achieve digital transformation:

Automate workflows by eliminating repetitive tasks and streamlining standard operations.
Improve decision support by leveraging analytics and embedded expertise.
Increase mobility by ensuring secure, on-demand access to information and expertise.
Implement change management by accelerating the adoption of operational best practices.
Upskill the workforce by enabling workers to acquire knowledge and experience faster.

To help refiners on a path forward to meet the challenges of transforming into a next-generation digital workforce, it’s also important to attract tomorrow’s leaders. There are currently millions of tech-savvy men and women preparing to join the workforce, but too few of them see refining as a desirable career path.

To ensure that it has access to a stream of qualified, motivated staff now and in the future, the downstream industry must shed its age-old reputation and promote the exciting high-tech aspects of the job effectively. The industry is on the cutting edge in many ways, but it simply isn’t engaging with recruits to show them how their engineering or programming abilities can be translated into a rewarding career. A step toward that goal is to become committed to partnering with higher education institutions to build an employment pipeline that will cultivate the industry.

By transforming the workforce, refiners can also maximize the return on investments—now and for generations to come.

Read the article and download the full Refiner’s Guide to Digital Transformation and Top Quartile Performance. Visit the Downstream Hydrocarbons section on Emerson.com for more on the technologies and solutions which enable you to realize a higher level of performance and agility, while ensuring that your operation is safe, reliable, and compliant at all times.

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Understanding the Importance of Gas Detectors, Even When the Safety Standard Doesn’t Help

Jim Cahill — Tue, 02 Feb 2021 04:00:59 GMT

In an Industrial Compliance article, Emerson’s Nick Pinto stresses the importance of gas detection for a safety system.

Anyone designing or working with safety systems for refineries and chemical plants must be fluent in the language of standards created by ISA, ANSI, IEC, UL, NFPA and other alphabet-soup regulatory organizations. When it comes to fire detection and suppression systems in the U.S., the National Fire Protection Association (NFPA) carries a lot of weight on a huge range of matters from wiring terminations to sprinkler systems. NFPA standards are enormous documents since they cover every imaginable type of facility, including but not limited to apartment complexes, hospitals, and oil refineries. Plus, they go into great detail on the individual topics.

Except when they don’t. Sometimes NFPA doesn’t have much to say on an important topic, which is the main point of my article in the Winter issue of Industrial Compliance. Combustible gas detectors should be part of any fire detection system, but someone looking for detail on how they must be deployed won’t get much help.

NFPA 72: National Fire Alarm and Signaling Code is normally used by system designers and inspectors in conjunction with NFPA 70: National Electrical Code. But an inspector wanting to evaluate use of combustible gas detectors has little to go on because NFPA 72, 17.10 Gas Detection is a very short section in the long chapter on initiating devices. How should gas detectors fit into the picture to ensure compliance?

Gas detectors in this context include Emerson’s Net Safety Millennium II SC310 Catalytic Bead Combustible Gas Sensor and Net Safety Millennium II SC311 Infrared Combustible Gas Sensors. These point -source detectors are designed for harsh environments common to refineries and chemical plants, and can detect the presence of combustible gases before they reach the low-explosive level (LEL).

[We’d include a reference to the open-path detectors, but there still does not appear to be a relevant web page, outside of the one for Spectrex.]

The key is to know combustible gases are present before a fire begins so the source can be shut off before the release ignites. Once a fire starts, an incident and necessary response escalate very quickly, with a huge potential for damage, disruption, and personnel injuries. Hence the importance of combustible gas detectors, summed up in the concluding points of the article:

The paucity of information on combustible gas detectors in NFPA 72 does not diminish the technologies’ capability or its importance in a comprehensive system.
Without specific instruction, it is all the more important to consult with experts for detector selection and placement.
The lack of clear standards can be an advantage since there are few constraints on technology selection. New detector advances can be adopted without having to wait for the standard to catch up.

Are combustible gas detectors part of your safety systems? If not, they should be as they provide an important layer of protection between product release and full-blown fire.

Visit the Flame and Gas Detection pages at Emerson.com for more on technologies and solutions for gas detectors and sensors, gas leak detectors, flame detectors, and aspirators. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.

The post Understanding the Importance of Gas Detectors, Even When the Safety Standard Doesn’t Help appeared first on the Emerson Automation Experts blog.

Wireless Protocols Vie for Industrial Markets, but Which is Best for Your Application?

Jim Cahill — Fri, 22 Jan 2021 17:29:54 GMT

In a Flow Control article, Emerson’s Tom Bass looks at new wireless protocols, including 5G, and opines on the validity of each.

Any company that has developed a new product for a specific market and purpose will eventually ask, “Where else can we sell this thing? What other industries have a similar use case where it could fit?”

It’s a natural question since finding new markets means greater sales potential. Here’s a case in point: wireless communication protocols. If you spend some time researching these, you will likely find there are far more of them than you imagined. If you can think of an application, such as your home’s water meter sending data to your utility, there’s probably a wireless protocol designed for that exact purpose.

Some of the companies that design a new protocol look longingly at industrial users and try to decide if they have a viable offering. Making such an evaluation on a practical basis from the user point of view is the main point of my article in the December issue of Flow Control. How do you determine value and practicality?

When examining these protocols with respect to specific industrial automation requirements, one can identify the leading protocols designed for the intended use cases. In processing facilities, the most common choices are Wi-Fi and 5G cellular for mobile worker and data backhaul, used with WirelessHART and ISA100 for process control and monitoring instrumentation. Choosing one over the other for each use case requires careful evaluation.

When doing an evaluation, the four main points to consider relate to range, data handling, power consumption, and reliability. The article goes into more detail on these, so give it a full reading. If you look at the characteristics of WirelessHART on those four points, it is obviously designed specifically for industrial instrumentation, but there are many other applications for wireless in an industrial facility. For example, Emerson’s AMS Trex Device Communicator has Bluetooth capability so it can communicate on an as-needed basis with many field devices without opening enclosures or wiring cabinets to make a physical connection.

But there is a larger question in the mix of wireless networks for data backhaul, wireless workers, and other data-heavy requirements beyond the capabilities of WirelessHART. To date, most plants are using Wi-Fi for this purpose, and Emerson offers its Wireless 1552WU Gateway that connects WirelessHART self-organizing networks to any host system with integrated Wi-Fi backhaul for security, scalability, and data reliability. This gateway offers host integration with DeltaV and Ovation, plus Modbus TCP provides universal integration and system interoperability.

Promoters of 5G look at this application and say they can do everything industrial users need and then some.

5G represents the latest generation of cellular connectivity, and it is reaching into the industrial world. Most general discussion touts enhanced mobile broadband (eMBB) for smartphones and tablets, with major improvement compared to 4G, aimed at virtual reality media, UltraHD video and other high-bandwidth applications. eMBB supports data rates up to 20 Gbps with up to 10,000 times higher traffic than 4G systems. Network speed and brute data-handling capabilities are truly extraordinary under the right conditions.

Is it better than Wi-Fi? For now, let’s say it’s different. 5G can do some amazing things, but it diverges conceptually from Wi-Fi in many respects, which the article discusses in greater detail. Some users will see those differences as advantages, others will not. For now, the jury is still out as products suitable for industrial installations are still largely under development.

Has your facility had any discussions on where you might be headed? Does 5G look like something you will consider in greater detail? How are you thinking about using it?

Visit the Industrial Wireless Technology pages at Emerson.com. Gain access to all your facility data with industrial wireless infrastructure for process instrumentation and wireless networks from Emerson, the expert in industrial wireless technology. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.

The post Wireless Protocols Vie for Industrial Markets, but Which is Best for Your Application? appeared first on the Emerson Automation Experts blog.

Storage Terminal Capacity Podcast Series

Jim Cahill — Thu, 21 Jan 2021 16:47:10 GMT

In March 2020 we were reminded that the Oil and Gas industry can be booming one moment and crashing the next. Companies’ operations staffs took a huge hit last year, where over 100,000 oil, gas and petrochemical workers were laid off. This created additional challenges for operators in maintaining process visibility and performing necessary operations and maintenance activities. The world’s oil storage capacity is improving, but analysts are predicting that it will take several years to recover back to what it was before this recent downturn.

Emerson can help you on your journey to terminal profitability, as you pivot and plan for the future.

In this Tanks and Terminals Podcast series on Optimizing Terminal Capacity, our experts will address challenges that terminal operators face and offer solutions that can help you more easily meet industry Top Quartile benchmarks and optimize terminal capacity. You will hear how recent digital innovations and applications can help you efficiently manage your operations, increase your labor and asset productivity and ensure greater volume deployment and inventory turnover.

We’ll cover topics to:

Realize Higher Profit Margins
Achieve Greater Labor and Asset Productivity Through Terminal Optimization
Achieve Optimal Truck Rail Loading and Unloading
Increase Tank Capacity and Reduce Costs

Emerson’s Manuel Arroyo, Director, Oil & Gas Industry Programs kicks off this podcast series with host Jim Cahill by highlighting some of the risks & challenges and previews some of the technologies that can help you make the right operational decisions to achieve terminal profitability.

Make sure to also visit the Optimize Terminal Capacity section on Emerson.com for more on ways to better manage planning and scheduling activities, operational workflows and processes, inventory calculations and capacity tracking.

Transcript

Jim: Hello everybody. I am Jim Cahill, and in today’s podcast I want to introduce a new series on optimizing storage terminal capacity. I am joined by Emerson’s Manuel Arroyo to introduce storage terminal optimization, and some of his colleagues you’ll be hearing from in future podcasts in this series. Welcome Manuel.

Manuel: Thank you, James. Hi everyone. My name is Manuel Arroyo. I’m the director for the oil and gas industry programs, and a subject matter expert at Emerson Automation Solutions. Welcome to this new podcast series on terminals capacity. From the oil crash, predicted recovery has slowed but is still on demand. Analysts expect global oil demand will take several years for recovery to where we were before March 2020. The world’s storage capacity has decreased due to low demand, and companies are looking to increase their capacity by either building new infrastructure, or through merchant acquisitions. This increased the complexity of their operations and the need to optimize them.

Jim: So, Manuel, what do you see as some of the major impact of this slowdown?

Manuel: Interesting question, Jim. Where we see our oil and gas business hit the most is in two major sections. One of them, it is the people, that is manpower and means expertise, and the second one is the budget flexibility. Look, just for the first one, over 100,000 oil, gas and petrochemical workers were laid off between March and August in the U.S. alone. This has a huge impact in operations. Just imagine, running operations with half of employees, this has a lot of implications. Let’s start from the commercial side. You are not going to be able to capture all the process activity sometimes. In operations you’re going to see a slowdown in the loading operations obviously and increase safety risk.

Jim: Wow, that loss of 100,000 people and trying to figure out how to keep the operations running, maintaining the terminal capacity, that sounds like quite a challenge. So, what are you and your colleagues going to cover in this series?

Manuel: My colleagues and I want to inform all of you of the recent innovations in digital technology that can help you to make the right operational decisions. This will streamline your commercial and field operations, reduce safety and financial risk, all this with the end goal to increase your terminal capacity. During this series, we will be covering the following topics: number one, how to streamline the commercial to operations execution cycle, number two, how to increase your labor and asset productivity, number three, achieve optimal loading operations, number four, increase shale capacity, and number five, mitigate costly transfer uncertainties. As you can see, this is more than just storage. It is also about terminal service capacity.

Jim: Yeah, it sounds like each one of those topics can drive better capacity or managing the capacity that you have. Could you elaborate a little more on the importance of each of these?

Manuel: Sure, Jim. As I pointed earlier, as companies grow to increase capacity, their operations complexity increases as well. They have to manage more contracts, more movements. Also, sometimes the type of movement changes or increases. For example, from only truck loading to truck and rail cars, to truck, rail cars, and barges sometimes. With the right technologies and software, they can realize a lot of benefits from reduced customer compliance, ensure safety, and optimize asset utilizations. But the most relevant improvement is in customer satisfaction and being able to capture more business.

Jim: Well, that definitely sounds like a lot of areas that can be optimized, and we look forward to hearing from each of the experts that we’ll be hearing in the future ones. So where can our listeners go to learn more and how would you like listeners to be able to contact you?

Manuel: Sure, Jim. The first one is tune into our terminal capacity podcast series, starting this January. You can also search on emerson.com. Look for the oil and gas industry, then go to Transportation and Storage. Click on Terminals and Optimized Capacity. Yeah, it is a long journey, but worth to try it. Or you can contact me, manuel.arroyo@emerson.com. Thank you.

Jim: And I know Manuel, you’re also pretty active in LinkedIn, so feel free to, folks who listen to this, reach out to Manuel that way. And we’ll provide a link there in the transcript. Well, Manuel I want to thank you so much for joining us today and giving us an overview of what’s to come. We look forward to kicking off more of the terminal series as we cross into the new year. And thanks again for joining me today.

Manuel: You bet, Jim. Thank you. And thank you everyone.

End of transcript

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Capital Project Success: Your Roadmap

Jim Cahill — Tue, 19 Jan 2021 15:28:16 GMT

The complexity of today’s capital projects is causing a widespread loss of value and confidence due to project overruns. Projects are larger, more technical, and running at a faster pace than ever before. Yet decades-old project methodologies can’t keep pace. And that means it is time to rethink capital projects and transform these outdated strategies with digital technologies, high-end expertise, and the power of automation.

When it comes to the current capital project environment, research and experience show that over the past 10 years, 65 percent of capital projects valued at over $1 billion have failed meaning they were either 25 percent over budget or 50 percent late.

Not only is valuable investment capital being wasted, but company performance is also damaged—which drags down company profitability, shareholder value, and the ability to grow the business.

To gain a better understanding of what’s been happening, Emerson worked with an industry benchmarking company and studied over 400 capital projects and found that Top Quartile companies completed the same project for half the cost and in half the time compared to fourth quartile companies. Two primary issues causing this type of variance are increased complexity and outdated methods.

Complexity of scope, challenging locations, and technical complexity may be obvious. But recognizing how “traditional” or outdated methods are holding us back is perhaps a new insight—especially when faced with creating a more sustainable business model in a rapidly changing landscape focused on competition, price pressure, and higher risk.

This article highlights how leveraging automation can ensure on time project completion with digital technologies that can automate workflows; wireless instruments that can eliminate field engineering and wiring costs; new analytics that create smarter plants, and the ability to build full digital twins of both the plant and the control system.

It shares how to start digitally transforming projects by eliminating costs, reducing complexity, and better accommodating automation design changes during the project with less impact on the schedule.

Working with an expert Main Automation Contractor (MAC) to help design and implement the best digital transformation strategy for the project is another step to achieving project execution success.

By following more effective methodologies and adopting new digital technologies, refiners can digitally transform projects and set the stage for maximizing the profitability and ROI over the next 20 to 60 years.

Read the full article in the Refiner’s Guide to Digital Transformation and Top Quartile Performance section on Emerson.com or download a copy.

The post Capital Project Success: Your Roadmap appeared first on the Emerson Automation Experts blog.

How to Select the Right Sensors for Wastewater Monitoring

Jim Cahill — Fri, 15 Jan 2021 17:59:26 GMT

In a Hydrocarbon Engineering article, Emerson’s Andrew Smith looks at the sensors used to measure effluents in refinery wastewater.

For those people responsible for compliance with EPA and other environmental regulations, it can seem like there are many hoops to jump through, but the right instrumentation makes compliance easier.

Monitoring water quality is the primary concern of my article in the November issue of Hydrocarbon Engineering. It looks at the sources of pollutants in a typical refinery and the technologies used to detect and quantify those specific pollutants found in specific streams. This is critical since it requires a balance of looking for all the right pollutants but without overdoing it.

To begin with, there is no reason to look for things that are not there. There is a short list of potential pollutants from a given source within a facility. The caustic hydrogen sulfide and mercaptan removal section of a unit is not likely to produce ammonia, so there is no need to look for it. So, the question becomes: how does the relevant effluent at this point in the process change water characteristics in a measurable way that can also indicate the amount of harmful pollutants?

Fortunately, most of the effluents present in a refinery change one or more of these chemical characteristics: pH, oxidation-reduction potential (ORP), and conductivity. When looking at a specific waste stream, such as sour water from a steam stripper, or condensate blowdown from a boiler, it is critical to choose the right approach.

Making correct sensor selections calls for cooperation between the plant’s internal engineering staff and trusted instrumentation partners. Questions of range, repeatability, accuracy, reliability, maintainability, and other performance characteristics need to be examined in specific situations. For example, in a given application, conductivity or pH could both be highly useful measurements, but conductivity might be less maintenance-intensive. In another situation, the opposite might be the case.

Fortunately, Emerson has a wide range of sensors for liquid analysis.

ORP and pH measurement technologies are similar in nature and Emerson’s Rosemount 3900 General Purpose pH/ORP Sensor can handle both. Its double junction reference aids in the sensor’s resistance to harsh environments and helps prolong sensor life. The double junction protects the reference element from poisoning ions—such as ammonia, chlorine, cyanides, and sulfides. The robust sensor design makes the 3900 reliable in the wide range of aqueous solutions found in pipelines, open tanks or ponds.

Conductivity monitoring is also important, and Emerson’s Rosemount 400 Contacting Conductivity Sensor can accurately measure electrolytic conductivity in a broad range of applications from high purity water to clean cooling water. The Rosemount 400 sensors are ideal for use in clean, non-corrosive liquid having less than 20,000 µS/cm.

What’s the situation at your plant? Are you struggling with keeping your emissions in line, or doing a great job protecting communities around the plant and downstream?

Visit the Emerson Liquid Analysis pages at Emerson.com for more on technologies and solutions for monitoring pH, ORP, conductivity, dissolved oxygen, ozone, chlorine, and turbidity. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.

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