Emerson Process Experts

Emerson's Jonas Berge is an active member in the ISA SP104 committee, responsible for advancing the Electronic Device Description Language (EDDL) standard (also known as IEC 61804-3.) You may recall Jonas from earlier EDDL posts. This standard creates interoperability between digital field devices from simple sensors to complex devices (drives, analyzers, etc.) with control and asset management systems. Interoperable communications include device diagnostics, asset management and user interface displays.

Jonas has written a short piece, OPC Made Easy, in the April issue of Control Engineering Asia magazine. In this article, he describes how EDDL can save many hours of OPC server configuration, which can help speed up a project's completion. For background, he begins by reminding readers how this important standard makes sharing data between OPC servers and OPC clients easy:

…external software in HMI clients and other users can easily access the wealth of detailed diagnostics and information in hundreds or thousands of intelligent devices around the plant.

Configuring OPC clients is easy: just point and click on data in the OPC server.

The challenge is in the configuration of the OPC server:

Configuring the OPC server includes entering device addresses and communication settings as well as creating the "namespace" which entails entering tag or descriptor for each and every piece of information along with the memory register address for the parameter as well as its data type, and range where applicable. This parameter "mapping" is the most time consuming and error prone part of OPC integration, but once done the rest is easy.

Jonas explains how EDDL can automate the creation of the OPC server configuration for devices digitally communicating via HART, Foundation fieldbus and Profibus. He writes:

Automatic OPC server configuration is made possible because EDDL is a descriptive technology similar to XML or HTML, declaring the properties of the data in the device for use by the auto-configuration mechanism. EDDL is the only device integration solution that is declarative.

Although not in the article, Jonas relayed an example to me where an AMS OPC Server was used to pass a slug flow alert from a Micro Motion HART device to an older distributed control system (DCS) that did not support HART communications pass-through. Before the solution was implemented to send this alert to the DCS via OPC, slug flow would cause over-charging of materials added to a batch. Now, the operators are alerted to slug flow conditions and can pay special attention to the surrounding process equipment.

The EDDL.org website remains the best source for information about this standard. You can also join the EDDL email list hosted by ISA to keep up and participate in the conversation around this standard.

Tags: EDDL | electronic device description language | SP104 | IEC 61804 | OPC | OLE for Process Control | HART communications | Foundation fieldbus | Profibus |

May 6, 2008 in Alarm Management, in Interoperability, in Measurement | Comments (0)

Last week I did a post about pipeline surge pressure relief and a technical guide about this written by Emerson's Daniel business. They are known for gas and liquid fiscal flow measurement solutions for the oil and gas industry.

I received a nice follow up note from Dave Seiler about a Latin American refiner who was fighting turbine meter maintenance problems due to large concentrations of foreign materials in the pipeline liquid flow. The problem was so acute that they actually had to install two meters in parallel so they could switch between meters while the other was being maintained.

The refinery engineers worked with the local Daniel team to replace the turbine meters with a 6-inch liquid ultrasonic flow meter. These do not have moving parts, unlike the turbine meters, which were being impacted by the particulates in the flow.

I didn't know much about the ultrasonic technology in flow applications, so I googled around and found a Hydrocarbon Processing magazine article reprint, Use liquid ultrasonic meters for custody transfer, in the Daniel area of the EmersonProcess.com website.

Dave is a co-author of this paper. The article does a great job of simplifying how the ultrasonic technology works. It also includes the math on how the ultrasonic flow measurement works.

My analogy, fresh from a rafting trip down the Guadalupe River, is to imagine that you're floating down the river with an ultrasonic transducer on one bank, and another on the other bank a little further downstream. Ultrasonic pulses are sent between the two transducers in each direction. The pulse traveling across the river from the upstream one to the downstream one will obviously travel faster since it's going across the river with the current. And of course, the reverse is true; it takes longer to travel across the river going upstream against the current. With the formulas in the article and enough perseverance, you can calculate the river's flow rate from these time differences. For the 3D world of pipe flow, the authors' explain:

The resulting time difference is proportional to the fluid velocity passing through the meter spool. Single and multiple acoustic paths can be used to measure fluid velocity. Multipath meters tend to be more accurate since they collect velocity information at several points in the flow profile.

Now back to the story… after the installation of an ultrasonic flow meter, the refiners saw that the meter was reporting low flow rates when the product in the pipe switched between gasoline and diesel.

The local Daniel service technicians collected maintenance logs using their Customer Ultrasonic Interface software (CUI) and sent it to the support team in Houston for detailed analysis. The team verified that the meter was working correctly for both liquids. They deduced that the flow was being diverted somehow during the transmix, or product switchover, where both products are flowing through the pipe until the switchover has been completed. This was possible because of the meters ability to accurately measure both flow rate and speed of sound of the liquid passing through the meter with extremely high accuracy.

The refiner verified that this is what indeed was happening where this transmix was being routed away through a smaller pipeline for further reprocessing. With the age of the refinery and the retirement of experienced operators, the current operators had not been able to see this transmix operation occurring in their process. The refinery engineers were impressed that the team in Houston could deduce this from their analysis of the data.

The refinery engineers involved in this project are presenting a workshop at this year's Emerson Exchange in late September. If you face similar challenges, you might want to catch this one.

Tags: flow measurement | ultrasonic flow meter | pipeline liquid flow | turbine meter | transmix | Emerson Exchange |

April 11, 2008 in Custody Transfer, in Emerson Exchange, in Measurement, in Pipeline, in Refining | Comments (0)

I received an email from Anand Iyer. He's a certified project management professional (PMP) and a project manager in Emerson's engineering center in Pune, India. His project experience covers the gamut from pharmaceuticals, bulk drugs and intermediates to oil, gas and petrochemicals.

He's sent me a paper he's written entitled, Collaborative Measurement Control System Engineering. It describes how measurements close to one another in the process can collaborate with one another to verify their operation. He describes an example around a distillation column:

Now let us take two temperatures (bottom temperatures) in a distillation column and a level measurement. When the level is normal, the two temperatures are same or have a fixed relationship between them. TI1 is placed at a lower level in the column (near bottom) and TC2 is at a higher level (and used for Temp. control). Now TC2 is generally used for control. We can safely say that if Level is normal, and TC2 is under maintenance, TI1 can be used for control (with a minor adjustment to Setpoint if required). Thus Level and Thermocouple TI1 put together can "collaborate" the measurement of Temperature-measurement TC2.

Anand contrasts the traditional approach to a failure with how collaborative measurement strategies can be used in control strategies to avoid outages or process disturbances. In the traditional approach:

…the first thing done if an element were to fail was to swap the elements (either during the shutdown caused by the failure) or by a planned outage or having the loop in manual and doing the swap. At times, we have also used our ingenuity and just swapped the wires at the analog inputs and tuned control setpoints to have the plant up and running in a very short time. And hopefully, in all that chaos, someone had the presence of mind to record the swap on the wiring diagrams.

Using a collaborative measurement strategy:

…says that if level is not low and TC2 is not available then TI1 can be a valid measurement. We alarm the operator that TC2 is not available, fine tune the setpoint if required… All this occurs automatically and there is no outage or disturbance that could result in quality issues.

He extends the thought to Foundation fieldbus devices where the final control elements themselves can perform the logical evaluations and select the available primary or collaborated measurement, increasing the overall robustness of the control strategy. Anand also extends his thinking to wireless devices and how they could be used in a collaborative measurement environment—not as a primary measurement, but as a collaborative measurement to check on other devices nearby.

I hope you'll give Anand's paper a read and add your thoughts.

Tags: collaborative measurement | project management professional | PMP | Foundation fieldbus | distillation column | measurement strategy | control strategy |

March 12, 2008 in Control Strategies, in Distillation Column, in Foundation Fieldbus, in Measurement, in Project Services, in Wireless | Comments (0)

Recently my Emerson RSS news Feed alerted me to a wireless application on a North Sea oil and gas platform. I sent a note to the team involved with this project asking about their perspectives.

I received great notes back from Jeremy Fearn, a Smart Wireless Specialist based in the United Kingdom and Rolf Jenssen, a manager in our Norwegian Asset Optimization organization.

The overall challenge this oil and gas producer faced was the desire to measure annular pressure of the wells remotely by replacing the local pressure gauges. These measurements monitor the integrity of the tubing and annulus in the area between the production tubing and well casing.

Now, from my days on oil and gas platforms in the Gulf of Mexico, I recall that adding pressure measurement around the wellheads can be difficult and cost prohibitive. As Jeremy points out, this requires cable tray, cables, installation, drawings, man-hours, transportation and accommodation of the team to do all this. Also, the areas around the wellheads are classified as hazardous areas.

The team found the easiest and least disruptive way to replace the existing local pressure gauges was to use a gauge adapter with the Rosemount wireless pressure transmitters. This provided a direct replacement of the manual gauges with the wireless devices.

Another challenge was the distance between the wireless gateway and the room with the automation systems and AMS Device Manager software. Jeremy described their solution to use the fiber optic option for an Ethernet connection to the gateway. A short length of fiber optic cable was used to connect from the wireless gateway to a nearby cabinet room. This room contained spare optical fibers, which allowed the team to connect through to the process Ethernet backbone.

The platform already had AMS Device Manager software used for on-line diagnostics of 125 valves equipped with HART DVC controllers. AMS Device Manager also included an AMS OPC server. This software pulled in all the wireless pressure readings from the wireless gateway. From here, the data was passed to an OPC client on the host automation system. The AMS software also tagged all the parameters in the wireless HART transmitters, making it easy to select a parameter showing the overall quality of the measurement. This meant the quality of the measurement also could be transferred to the operators on the automation system. For detailed information about the status, configuration and health of the wireless transmitters, AMS Device Manager with EDDL files is used, clearly showing any failures.

Rolf also noted that the automation system's OPC client during the set up uploaded all of the values and parameters available from the AMS OPC Server, taken from all the platform HART devices including the wireless devices. After the selection of the pressure, temperature and the overall quality value, the team deleted the whole upload, but the selected values for the OPC links were now updated continuously to the operators, included the annular pressure measurements.

Initially, the staff engineers thought that two wireless gateways would be required, due to the density of the platform and production equipment. It turned out that only one gateway was required. All devices were able to communicate with the gateway. In fact, the device mounted furthest from the gateway still found a direct path! As more devices are added in the future, the strength the self-organizing network will be increased from additional wireless signal pathways.

The team took two days less than expected to complete the installation, and the oil and gas producer's staff has performed similar installations on other platforms without help from Jeremy or the other wireless consultants.

The real benefit is that the annular pressured is monitored continuously by the operations staff rather than twice a day through manual readings. Pressure drop in the annulus might indicate a problem with the well. These continuous measurements provide operators an opportunity to take corrective action much earlier to help avoid well rework and lost production.

Tags: wellhead | annulus pressure | annulur pressure | EDDL | OPC server | self organizing network |

March 11, 2008 in Asset Optimization, in Measurement, in Oil & Gas, in Wireless | Comments (0)

I heard about entrained gas, but it was never really clear to me exactly what it was until I read an article by Tim Patten, Handling Entrained Gas, in Flow Control magazine. Tim is the director of measurement technology for Emerson's Micro Motion Coriolis flow and density measurement business.

In the article, he describes three categories of entrained gas: slug, bubble and empty-full-empty flow. Each poses unique challenges for flow and density measurements. Slug flow is large bubbles forming in liquids and usually found in improperly or incompletely filled, long-distance piping. Other sources of bubbles are leaks in pump suction or tank agitation, which cause air to be introduced into the line.

Slug flow is large bubbles forming in liquids and usually found in improperly or incompletely filled, long-distance piping. Other sources of bubbles are leaks in pump suction or tank agitation, which cause air to be introduced into the line.

Bubble flow as the name suggests is more of a continuous distribution of gas bubbles in a liquid process. These bubbles are commonly found in highly viscous liquids, like toothpaste or peanut butter, as Tim puts it. Other causes include high-speed agitation or pumping. Pumps with broken seals or ones that cavitate can also introduce bubble flow in the process.

Empty-full-empty (EFE) flow is common in batch-type processes. This batching is commonly found with railcar and tanker truck loading. A variation is multiphase flow, with multiple density phases with some degree of separation and a mixing layer between them. This type of flow is common for oil and gas producers with the pipelines containing gas, oil, and water before going through the separation process.

These three entrained gas scenarios and their impact on flow and density measurements led to research and development efforts to improve these measurements. Tim describes results from this R&D:

…that four key elements played a role in the entrained gas performance for Coriolis meters — the signal processing speed, processing algorithms, sensor design, and meter stability independent of environmental changes.

Entrained gas in slug flow and EFE caused frequent and large disturbances in the flow measurement. Digital signal processing at a very high rate in the Coriolis electronics allows many variables to be simultaneously measured and synchronized with the disturbances to allow these disturbances to be filtered out of the signals sent back to the automation system. Tim cites an improvement from 20% error rates with traditional measurement technologies to 1% with today's Micro Motion Elite Coriolis flow and density meters.

For bubble flow conditions, Tim describes the importance of the sensor design and sensor stability. He describes why:

Sensor design is important because the critical bit of information is the relative difference in motion of the bubbles and fluid. Sensor stability is important because sensor vibration during bubble flow can be noisy and can cause the sensor to couple to the environment.

By getting this design and stability right, the noise introduced by the bubbles will cause minimal flow measurement errors.

These technologies allow measurements on applications once thought not possible or in applications where a problem has introduced entrained gas, such as a leaky pump seal.

Tags: entrained gas | bubble flow | slug flow | empty-full-empty | sensor design | sensor stability | Coriolis flow | density measurement |

February 11, 2008 in Measurement | Comments (0)

Inside the Emerson firewall, we have a growing community of bloggers who share their expertise with other Emerson folks and local business partners. Hopefully more of these voices will emerge over time, sharing their expertise externally with the world.

I saw a post this week from the Rosemount team about installation best practices in the power industry. Power Industry leader, Rajesh Nogaja lead the effort to show how Rosemount products could be used to improve the power generation process.

On the external EmersonProcess.com website, the team created a graphical interactive application, Proven Installation Practices in Power Applications, to show these opportunities.

For instance, if you click on the steam and gas turbine area of the graphic, the application takes you to a closer view of the steam, gas turbine, and balance of the plant graphic.

Once you click on the graphic to activate it, the graphic becomes dynamic and shows what measurement can be added to improve the operation of this part of the plant. Marker one points to the saturated steam flow measurement. It displays the best practice, in this case, having accurate measurement helps accurately calculate thermal cycle efficiency for these turbines.

I asked Rajesh from his experience which measurements were most often overlooked and a source for energy efficiency improvement. Rajesh pointed to condensate level measurements in heaters, condensers and deaerators. Accurate level control can optimize thermal cycle efficiency and improve plant heat rate. Guided Wave radar, which is immune to high vibrations and density changes, improves the condensate level controls under heavy load fluctuations. This measurement accuracy is not possible with conventional DP level or displacer type technologies.

Another often-overlooked area in most of power plants is accurately measuring main steam flow and extraction steam flow. These measurements are generally inferred from turbine first stage pressure or condensate flow. The direct flow measurement enables online heat-mass balance and optimizes part load and full load thermal efficiencies in the plant.

If you're responsible for optimizing a power plant and haven't done so already, look at these proven installation practices. I invite your comments on your experiences with key measurements and their impact on efficiency.

Tags: power industry | installation best practices | steam turbine | gas turbine | thermal cycle efficiency | saturated steam flow | thermal cycle efficiency | steam flow |

February 5, 2008 in Measurement, in Power | Comments (0)

As he announces yet another eBook now available, ModelingAndControl.com's Greg McMillan continues to share his control expertise with the world.

Greg describes the book Biochemical Measurement and Control:

When Monsanto was making the transition to a life science company, I had the opportunity to work on fermenter measurement and control for various genetically engineered products. Important opportunities identified then such as the application of mass spectrometers, dissolved carbon dioxide probes, and inferential measurements of metabolic processes have come to fruition today opening the door to more advanced process analysis and control techniques. Additionally the applications gave me a chance to apply my expertise in pH measurement and control in new ways and dig into the practical aspects of dissolved oxygen measurement and control.

As he goes on to mention, the progression of technology and new thinking prompted an updated version, New Directions in Bioprocess Modeling and Control: Maximizing Process Analytical Technology Benefits published by ISA in 2006. This book:

…provides an updated view and details on new tools for batch modeling, analysis, and control. This ISA book includes the development of neural network inferential measurements of dryer moisture by Washington University in Saint Louis and my first principle dynamic fermentor models for the National Corn to Ethanol Research Center. The book concludes with an excellent review of new technology for batch analytics by the University of Texas.

As I had mentioned in an earlier post, Greg has chosen to make many of his works available as free eBooks once the copyrights are returned to him. So, for the next many years, the Bioprocess book is available for purchase from the ISA folks or in the DeltaV Bookstore, along with many other great books we've discovered along the way.

We live in great times where many with expertise make it freely available. If this expertise happens to intersect with our interests and we have some bandwidth to absorb it, we're but a mere Google search (or whatever your favorite search engine happens to be) away. It just wasn't this easy way back when!

Tags: biochemical | bioprocess | life science | Greg McMillan |

October 26, 2007 in Education, in Life Sciences, in Measurement | Comments (2)

You may have seen quite a bit of news coverage (here, here) on wireless technology as it applies to plant instrumentation. At the recent Emerson Exchange, Emerson also announced some wireless news.

If you are an automation engineer, you might have thought about some applications where you would like to try this technology.

Your best course is to start with a simple business case. Perhaps the operators perform rounds to get readings from gauges and instruments not connected to the automation system. Having this information and associated diagnostics coming from wireless devices could possibly make your plant's instrument technicians more efficient.

I caught up with Mark Sagstetter in Emerson's Rosemount Measurement business. He recently went to a refinery along with John Biscone, a service technician in Emerson's Instrument & Valve Services business. Operator and instrument technician efficiency was the very business case this refinery was pursuing. Mark and John were contracted to provide their expertise to help plan the network and installation process of the wireless instruments and gateways. Much like the early days of digital bus technologies, this expertise can help automation engineers establish best practices for planning and executing future wireless installations.

In the course of a two-day site visit, they worked with the plant engineers and identified five process units including four tank farm locations that met the criteria for increasing operator and instrument technician efficiency.

My understanding when talking with Mark is that there are basically two overall best practices to follow when implementing a wireless field network. The first is planning the wireless network and the second one is the network installation.

When executing the best practice of planning the Self-Organizing wireless networks, Mark and John like to have scaled site drawings. Unfortunately, in this case, scaled drawings were not readily available. Necessity being the mother of invention prompted the team's great idea to use Google Earth to generate site maps. They used the printouts during the walk-through of these process units to help envision device locations, gateway locations, plot anticipated communications, and to help identify possible impenetrable situations.

As part of the best practice of planning the network, it is a good idea to plot at least two paths of anticipated good communications for each instrument. Using a color-coding scheme, with one color to mark anticipated good communications paths and another color to mark potentially interrupted paths of communication, John and Mark were able to use this process to help understand how the network may function when installed. It also helped to understand, plan for, and possibly eliminate possible pinch points and/or possible impenetrable situations before the actual installation.

With every Self-Organizing wireless instrument being capable of being a router (sending and receiving messages from other instruments), possible pinch points and impenetrables are easily overcome. This is accomplished with the addition of measured points or instruments that act as routers or range extenders.

During the installation-planning portion of the site visit, Mark and John recommended the plant engineers follow the wireless installation best practices. To do this, the plant engineers would need to power and commission the gateway first. Then install, power, and commission the instruments, starting with the instrument closest to the gateway and continue working outward from the gateway. The instruments' connectivity to the gateway should be verified each time after installing, powering and commissioning the instrument.

One thing I noted in my conversation with Mark is that the instruments mount with standard process connections. Engineers have been using these standard connections for years. The actual mounting location for the instruments and gateways were determined by providing a forearm's length (a measurement device every instrument technician has with them at all times) of space between the antennas and any wall or metal structures to avoid signal attenuation.

Installation would continue by powering, installing, and commissioning instruments outward from the gateway, until all the devices have been brought on-line. By installing the instruments in this fashion, the actual formation and connectivity of the wireless Self-Organizing network can be compared with what was expected during the best practice of planning the network.

Beyond the immediate need to help the plant engineers plan a smooth installation at this refinery, Mark and John helped them establish best practices to aid in future wireless projects/installations.

Tags: wireless field network | self organizing | wireless site planning | site drawings | wireless best practices |

October 25, 2007 in Measurement, in Project Services, in Wireless | Comments (2)

If you're an automation professional and not already subscribed to the ModelingAndControl.com blog, you're missing some great stuff.

Greg McMillan has recently posted three "sensible sensor installation" posts:

• Sensible Sensor Installation
• Sensible Sensor Installation - Follow Up
• Sensible Sensor Installation - Tips

Greg offers his rules of thumb based on his vast plant experience for installing temperature and pH sensors. Here's an example from his initial post:

The best sensitivity from a temperature or pH sensor can generally be achieved by an installation where the tip of the thermowell or electrode is in the center of the pipeline. This is particularly important when there is a high viscosity fluid such as a polymer for temperature control or concentrated sulfuric acid reagent for pH control. For temperature, it is also desirable to maximize the insertion length in the center line to reduce the thermal conduction error from the tip to the flange. The insertion of the thermowell into an elbow affords this opportunity.

I know when I was a young systems engineer I would have really appreciated more rules of thumb to give me grounding on some of the things I needed to consider. Experience teaches these things, so any shortcuts to gain these experiences are greatly appreciated.

As I mentioned in a Web 2.0 presentation at the last Emerson Exchange, many ways are emerging to share your process automation expertise. A blog is one way, but other ways include adding/modifying entries in Wikipedia, social bookmarking with Del.icio.us, and sharing interesting posts you come across with web-based RSS readers like Google Reader.

If you've not yet taken the plunge to see what subscribing to RSS feeds is all about, see the screencast of how to subscribe to this blog, and how to import my blogroll. This is my way of helping get you jumpstarted to these rules of thumb with many automation and process industry-based blogs, including Terry and Greg's ModelingAndControl.com.

Tags: pH | sensor installation | thermowell |

October 19, 2007 in Education, in Measurement, in pH Control | Comments (0)

Those of us with teenage kids, or memories of their kids as teenagers, or even what we were like as teenagers may recall the question, "Why do I have to learn ____ if I'll never have to use it?" This is very fresh in my mind because I had that very conversation the other night. The blank in this case was chemistry. My point was that you really have no way of knowing what you'll need to know so you might as well learn it.

Well today, I'm reading an article from the August edition of Hydrocarbon Processing magazine written by Air Product and Chemical's Win Hoglen and Emerson's Julie Valentine, a member of the Micro Motion business. The article, Coriolis flowmeters improve hydrogen production describes how accurate steam-to-carbon ratio control improves efficiency in a reforming hydrogen plant located within a refinery. The article explores the chemistry in the reforming process converting the light hydrocarbons (methane, ethane, propane, butane) and water (in a superheated steam state) into hydrogen and carbon monoxide. A shift reaction then converts the carbon monoxide and water into carbon dioxide and hydrogen.

For those not in the refining industry, this hydrogen is needed to scrub the sulfur out of gasoline and diesel to meet the clean fuels regulations that countries around the globe have adopted. The sulfur reacts with the hydrogen to make hydrogen sulfide and then it is further processed into elemental sulfur.

The thrust of the article is not the chemistry lesson I just described, but the challenges to most efficiently produce this hydrogen. A major challenge is the chemical composition of the natural gas since:

…the amount of steam required for the reforming reaction can vary widely depending upon the number of carbon atoms per molecule of the gas (i.e., one molecule of steam is required for each carbon atom, but there can be from one to four atoms).

Traditionally, volumetric flow measurements were used which usually involved differential pressure measurement and gas chromatograph or mass spectrometer analysis. Calculations determine the actual mass flow (carbon mole flow.) Errors in the carbon mole flow result from errors in the volumetric flow when the composition changes. Also, this analytical equipment requires regular maintenance and steam flow must be increased to handle any spikes in carbon mole flow during this maintenance period.

There are problems with both too much and too little steam flow. Too little reduces catalyst life, and production instability that may lead to a costly plant shutdown. Too much steam wastes energy and may require additional capital investments for more steam capacity. The measurement and control challenge is maintaining a constant steam-to-carbon ratio.

Coriolis flowmeters, through the Coriolis effect, measure actual mass flow very accurately and require less maintenance. The drawback is that the mass flow measurement cannot distinguish impurities like nitrogen and carbon dioxide in the natural gas supply.

The article describes testing done where methane concentration ranged between 78% and 89% and ethane between 7% and 15%. Maximum variation in the steam-to-carbon ratio was 0.02 units of steam, much better than the 0.2 in the traditional measurement method. The percentages of nitrogen and carbon dioxide were relatively stable.

From the testing done at various Air Products and Chemical facilities, Micro Motion Coriolis flowmeters are well suited for a natural gas stream that has relatively fixed percentages of inert gases or nitrogen concentrations that do not vary outside of 3% less than design.

A final note, I forwarded this article on to my teenagers to demonstrate the point that one never knows when one might need to know something learned in one's past.

Tags: reforming hydrogen | clean fuels | coriolis flowmeter | carbon mole flow | differential pressure | gas chromatograph | mass spectrometer |

October 8, 2007 in Hydrogen Reforming, in Measurement, in Refining | Comments (0)

As more people discover various posts over the past year and a half, I receive a number of great questions. Here is a recent one. The specific operating parameter details have been omitted, but I wanted to share the flavor of the question and the answer.

We have a customer that uses a turbine flowmeter for natural gas metering. Based on the furnace-cycle time demand, cubic gas volume demand, no-flow shutdown time, our supply pressure at the metering station, and piping distances between metering station and furnace, we´d like to calculate the Dynamic Response Error due to the shutdown time in this system.

Jorge Gomez is an application manager in Emerson's Remote Automation Solutions business and is located in Brazil. He also provides support for Daniel flow products. Jorge worked many years in Brazil's national flow lab and has quite a number of contacts with flow technicians in TÜV SÜD's NEL, Germany's Physikalisch-Technische Bundesanstalt (PTB) and the US National Institute of Standards and Technology (NIST).

Jorge provides the following guidance:

Measurement of gas flow with turbines in a cyclic flow rate as you are asking is always a big problem--the main reason is that the turbine meter has a natural inertia in the rotor that cause a overmetering when the flow rate stops (the rotor keeps turning a time after the flowrate stops.) Usually this overmetering is not totally compensated by the rotor inertia when it starts to move when the flowrate returns. In other words, a turbine meters tends to show a positive error in a cyclic flowrate.

The estimation of this error is not easy, because it depends on the dynamic response of the meter that is variable depending on the model, design of the blades, mass of the rotor, wear of bearings and even the flow profile and how the flowrate changes (suddenly, slowly, pulsating, etc.)

There is a good study presented in ISO TR 3313 standard (measurement of fluid flow in closed conduits-guidelines of the effects of flow pulsations on flow measurement instruments). Despite this standard's focus on orifice plates, there are sections covering turbines (6.2) and vortex (6.3)--these are meters especially susceptible to unsteady flow.

This standard presents a theoretical approach, but the main question is estimates the dynamic response parameter, that is strictly empiric (obtained from experiments). This standard suggests this parameter for turbines from 2" up to 6" for gas and liquid flow, but the suggested parameters can be always questioned. You can also obtain this parameter from experiments on a calibration bench, although I don't know if this is possible in your case.

The standard also presents a very comprehensive bibliography, and you can purchase and download it from the ISO site.

From a practical point of view, maybe the best solution, especially if this is a custody transfer measurement--as it seems to be--is thinking about use of a flow sensing technology less affected by unsteady flow, like ultrasonic, Coriolis or even differential pressure measured across orifice plates.

Tags: flow measurement | turbine meter | natural gas metering | dynamic response error | cyclic flow |

August 27, 2007 in Measurement, in Oil & Gas | Comments (0)

An RSS search feed pointed to a Process and Control Today news item about the opening on a new Emerson European flow center. This center provides comparison, selection, final assembly, configuration, calibration, testing, support and training for quite a range of Emerson Process management flow brands including Micro Motion, Rosemount, and Brooks Instrument. The flow technologies include Coriolis, magnetic flow, vortex, thermal mass flow, and variable area meters.

The center was built to help process manufacturers primarily in Europe, the Middle East and Africa. With so many technologies, each have their advantages in different applications, it was important to have a common area where manufacturers could work with product and application experts to properly select and configure the best solution for the application.

I caught up with Emerson's Henk Verweerd who shared some highlights with me. The center, located between Arnhem and Utrecht in the Netherlands, supports seven languages, employs 275 people, and covers over 9000 square meters of floor space. In addition to the technical and application support, the team performs project and order management, repair management, and creation of documentation for projects and required regulatory agencies.

With the trend toward project modularization to decrease project schedules, the team helps instrument integrated systems for railcar, ship and truck loading/unloading, pipeline/LPG/LNG/gas metering, and proving Coriolis meters. The flow center includes four mini-plants fully instrumented with Foundation fieldbus devices to provide hand-on training for flow meters and applications, including the diagnostics these devices can provide to the automation systems.

Henk mentioned that the whole reason for the facility was to bring together experts from the various product lines to be able to work with manufacturers and quickly arrive at the best solution. It also helps provide better service, support, and input for future product improvements.

Tags: flow meter | flow measurement | foundation fieldbus | Coriolis | magnetic flow | vortex | thermal mass flow | variable area meter |

August 3, 2007 in Education, in Foundation Fieldbus, in Measurement, in Support Services | Comments (2)

Process manufacturers continue to seek ways to improve their energy efficiency, due to the high cost of energy. Corrosion and solids deposition in boilers, condensers, and steam turbines reduce the efficiency of this equipment and increase energy usage. This can also lead to unscheduled downtime if the conditions persist long enough to cause equipment failure.

One important way to minimize corrosion and the formation of solid particles is to have ongoing, accurate and reliable pH control in the boiler water, boiler feedwater and steam condensate, and main steam (carryover.)

The challenge is that these applications are often very low in conductivity. This is a challenge for continuous pH measurement due to the unavoidable formation of liquid junction potentials in the reference sensor. These cause offsets and instability in the pH measurement.

Emerson's Brian LaBelle, a power industry manager for Rosemount Analytical liquid analytical devices, explained these junction potentials are caused by spontaneous migration of ions from more concentrated to more dilute solution within a pH sensor electrode. What happens is a charge separation occurs among the various ions present. (At the word "ion", my mind raced back to those repressed memories of college chemistry lectures...)

Sometimes a severe junction potential occurs when there is an imbalance of negatively and positively charged ions across the liquid junction found in the basic reference electrode. The lower the porosity of the junction, the greater is the charge separation across this junction.

Sounds like we've gone a long way from the original problem of keep the equipment from corroding and being gummed up with solid particles.

Brian brought me to the solution by explaining that the technology team came up with the solution of replacing the diffusion junction with an open capillary (that's a hole for most of us.) Actually, this is not new or innovative, but what is innovative is that precise, laser drilling on a micro-scale of tens of microns is far more precise than what can be achieved with a twisting, mechanical bit. To minimize the junction potentials and provide more accurate measurement, the optimum capillary is laser-drilled at 25 microns in diameter. This capillary is also tapered outward to the outlet filter to help avoid clogging.

As we depart the micro world of ions and laser holes and return to our world of boilers, condensers, and steam turbines, the pH measurement with the Rosemount Analytical 3200HP pH sensor provides more accurate and reliable continuous measurement to ward off corrosion and solids formation. This means more reliable, efficient operations for this energy-consuming equipment.

Tags: pH measurement | pH sensor | energy efficiency | corrosion | boiler | condenser | steam turbine |

July 19, 2007 in Analyzers, in Boilers, in Measurement | Comments (0)

There has been quite a bit of lively discussion around comparisons with HART and Foundation fieldbus. The first item someone pointed out to me was a paper done by Jim Russell, the Chair of Australia's Foundation Fieldbus End User Council, entitled HART v FOUNDATION FIELDBUS – THE FACTS and THE REAL DIFFERENCE. It compares from a strong Foundation fieldbus perspective as indicated by:

Don't believe all the "hype" given out by manufacturers, especially those that tell you that you can get everything provided by Foundation Fieldbus with HART.

Then John Rezabek wrote a piece for ControlGlobal.com entitled, Users driving the bus. He created a stir with these words:

Newer HART I/O promises support for FF-like diagnostics, but some end users feel they're getting a smokescreen when they ask suppliers to clarify the real capabilities and limitations. DCS vendors, eager to win upgrade jobs in brownfield sites, should be telling their customers how much of the installed base of HART devices will need upgrades to support the watered-down, fieldbus-like diagnostics.

Walt Boyes in his Sound Off blog wrote a post A Word from Ron Helson at HART. Ron responds:

The statement about "watered-down, fieldbus-like diagnostics" is also very ironic and misleading. Contrary to the implication, the fact is that all HART-enabled devices – dating back to the early 90's – contain device status and diagnostic information that is easily used by today's HART-enabled automation and I/O systems without any upgrade to the device. Users evaluating their automation system and field communication protocol options must consider many issues including; device replacement, training, project risk, infrastructure upgrades, automation and I/O system upgrades and others. In many cases, total cost vs. benefits have shown HART to be the most cost-effective option.

The discussion continued with a response posted by John Rezabek.

I thought I'd take a different approach and look at what the protocols were designed to do, and how those original design goals influence protocol functionality. Emerson's Tom Wallace recently wrote a white paper entitled, Functional Comparison of HART and FOUNDATION fieldbus. It comes right out by describing the different design objectives of the two technologies.

Prior to digital communications protocols, 4-20mA analog transmitters required multimeters and screwdrivers to adjust potentiometers to range transmitters. Other potentiometers adjusted calibration, zero settings, and damping factors. Signals drifted and required constant maintenance. Electrical interference causing offset were other issues which required maintenance attention.

In the whitepaper, Tom summed up the HART design objectives this way:

When devices became smart, better ways to configure, calibrate, maintain devices, and communicate the process variable became possible. The HART protocol was developed to address this problem set. It had one huge market adoption advantage over other protocols of the day, in that it was not intended to solve all the problems of analog. Process control was still expected to be done from the 4–20 mA signal. Although this solution was technically inferior to a fully digital protocol, it maintained compatibility with the entire control system infrastructure installed in the field. HART was extended to provide the process variable digitally, but this capability is largely unused.

And the Foundation fieldbus design objectives:

FOUNDATION fieldbus was designed to support all the configuration and maintenance capabilities of HART and more. It was designed to be a completely digital process control network capable of being the control system. It does all the things that a regulatory control system does. It is deterministic and real time, handles alarms and alerts, has trending capability, provides the function blocks used for basic and advanced regulatory control, and the sequencing and logic associated with it. To accomplish this larger set of goals, it needs to support more robust messaging and processing power.

In addition, FOUNDATION fieldbus was designed to support all the configuration, calibration, diagnostics, setup, and maintenance activities associated with both devices and the control strategy.

The whitepaper goes on to compare various attributes including:

• Compatible with 4–20 mA control host
• Compatibility with existing control wires
• Communications robustness
• Multivariable capability
• Control via digital signal
• Control/calculation capability
• Accuracy, Stability, and reliability of the process variable
• Availability of process control
• Alarms and alerts
• Ability to access and deliver diagnostic information
• Compatibility with existing knowledge base and work practices

The bottom line is that both HART and Foundation fieldbus continue to provide value for process manufacturers and continue to improve, taking advantage of advancements in technology. As such, Emerson continues to invest in both these communications protocols and take advantage of the rapid advancements in technologies brought to us courtesy of Moore's Law. The different initial design objectives shape what capabilities each protocol can deliver now and in the future.

Tags: Foundation fieldbus | HART | diagnostics | communications protocols |

April 30, 2007 in Foundation Fieldbus, in Measurement | Comments (2)

In a recent Control magazine article, First the application, then the product, Editor in Chief Walt Boyes wrote about the importance of thinking about the application before selecting a level measurement technology. He wrote:

Before you do anything else, you have to have the application parameters. Most of us get so practiced with instrumentation design that we seem to start with the last ISA S20 instrument specification form we worked with and just plug it in. But the S20 forms were not designed to be application selection forms. You start with the sensor or transmitter. That's backwards.

Walt shows a level measurement continuum chart from very easy applications to nearly impossible ones and the types of measurement technologies which may be suitable.

I passed this article by Sarah Parker, an application manager in Emerson's Rosemount measurement division, for her thoughts. She agrees wholeheartedly that level measurement can be more complicated than it appears. For anything beyond the "very easy" as Walt puts it, there is no simple answer to the question, "What level technology should I use on my XYZ level application."

Sarah stressed that there are 3 parameters you must consider together: the technology, the installation, and the application conditions.

On the level measurement technology it's important to understand its capabilities. Questions you should answer include:

• What are its pressure and temperature limits?  
• What is its range capability?
• What is its primary mode of level detection? 
• Is it using mass, capacitance, or a distance measurement to make determine level?
• What are the restrictions on its use?
• What conditions will impact its performance?

On the specific installation:

• What connections are available on the tank? 
• What size and style are they?
• Where are they located in reference to the material you want to measure and any internal structures?
• How big is the vessel/structure?
• Are there any valves?

And on the application conditions:

• What is the expected pressure and temperature ranges?
• What are the properties of the material being measured--liquid or solid, corrosive, viscous, sticky, or crystallizing?
• Do any of its properties such as density, dielectric, or conductivity change?
• Is there agitation?
• Is there foam?
• Is the material vaporous?
• Is there steam?

Sarah summed it up well that ideally you want to find a technology that is able to handle all the application conditions, fits on the existing connections on the vessel and fits within your budget. If you have some thoughts on this, join the conversation and add a comment.

Tags: level measurement | level transmitter | level sensor | level application |

March 2, 2007 in Measurement | Comments (0)

While thumbing through the November/December issue of Pharmaceutical Manufacturing magazine, I came across a great article, Getting the Most from Coriolis Flowmeters in Pharmaceutical Processes, co-written by Vince Salupo of Eli Lilly and Franki Parson of Emerson Process Management's Micro Motion division. It's a great article for discussing the advantages and disadvantages of bent-tube vs. straight-tube meters depending on the requirements of the application. If you are already well-versed in Coriolis flow technology, this may all be too basic for you. If you're like me and not as well-versed, the article is worth a read because it makes the complex understandable.

Coriolis meters provide mass flow and density measurements, and are available in both bent-tube and straight-tube design. The article discusses the two types of designs and their advantages specifically in Life Sciences applications. The bent-tube meters have better accuracy and turndown. The straight-tube meters offer improved drainability which is something critical for pharmaceutical and biotech manufacturing processes which have clean-in-place operations to clean and sterilize the process piping between batches. The choice for of Coriolis design most suitable really is based on the application. If accuracy and repeatability are the overriding concern, the bent-tube technology is recommended. If raw material contamination within a batch or between batches is the key concern, the straight-tube flowmeters are recommended.

Another reason for the popularity of Coriolis flowmeters in Life Sciences manufacturing applications is their non-intrusiveness into the process. There are no fluids or moving parts that can cause problems on failure. Only the inside of the flow tubes touch the process.

The article further explores specific challenges found in Life Science applications like API synthesis and purification, formulation, and high purity water and what you should consider in selecting bent-tube versus straight-tube Coriolis meters for these unique applications.

I hope others considering their options in these types of applications found the Pharmaceutical Manufacturing article as clear and succinct as I did.

Tags: Coriolis | flowmeter | straight tube | bent tube | Life Sciences | Pharmaceutical | Biotech | drainability | clean in place |

January 5, 2007 in Life Sciences, in Measurement | Comments (0) | Trackback (0)

You might think because I work for Emerson, that I know all the developments going on. Far from it… I try to create this illusion by subscribing to the personalized RSS search over at MyEmerson News, in addition to my RSS subscriptions to the growing number of bloggers in our world of process automation.

The news blurb said:

Vortex technology has traditionally been preferred for measuring flow in saturated steam applications, but users also want a compensated mass flow output. Emerson's new Rosemount MultiVariable Vortex Flowmeter combines the benefits of proven Rosemount vortex technology with a temperature-compensated mass flow output directly from the meter. Besides reducing process variability, the new flowmeter lowers total installed cost of temperature-compensated measurement points by 25%.

I caught up with Marketing Product Manager Eric Schmidt to explain why this is good for saturated steam applications. Saturated steam is used in many manufacturing processes in the refining, chemicals, pulp and paper, pharmaceutical, food and beverage, and district heating industries.

Eric described how a temperature compensated mass flow of a vortex meter for saturated steam typically required external sensors and a flow computer to do the calculations. This new multivariable flowmeter includes everything necessary to do the calculations within the flowmeter and send it back to the automation system via HART digital communications, pulse output, or conventional analog 4-20mA signals.

By eliminating these separate components the cost of installation and ongoing maintenance is reduced. Eric calculates the installation cost savings by what is eliminated from externally compensated saturated steam measurements. These include the thermowell, temperature sensor, temperature transmitter, wiring, commissioning, and either separate flow computer or calculations in the automation system.

On the maintenance front, the technology team did something unique by designing a non-wetted temperature sensor in the flowmeter which can be replaced without shutting the process down—always a good thing for plants seeking maximum manufacturing efficiency.

Tags: vortex flow | multivariable | temperature compensation | mass flow | HART |

November 30, 2006 in Boilers, in Measurement | Comments (0) | Trackback (0)

It's always a pleasure to highlight the work of our technologists around Emerson Process Management. It's even better when their work is recognized by ISA, a premier organization for automation professionals. Congratulations to Martin Zielinski and Carl R. Jones on their recent awards for outstanding achievement.

Martin, the Director of HART and Fieldbus technology in Emerson's Asset Optimization division, was elected to the distinguished grade of ISA Fellow for his significant contributions in the development, standardization, and deployment of digital communications technology. Through his career he has worked in the forefront of some of the automation world's leading open, interoperable communications standards including the HART Field Communications Protocol, the FOUNDATION fieldbus communications standard, and the Electronic Device Description Language (EDDL). In fact, for two years while the Fieldbus Foundation was getting started, Martin served as its Chief Operating Officer. If your automation system or asset management software is receiving diagnostic information from intelligent field devices, you can bet that Martin's leadership and expertise went into it somewhere along the line from his work on these consortia and standards bodies.

Carl, retired from and now consulting with Emerson's Rosemount Analytical division, received the UOP Technology Award for the development of process analyzer applications, particularly those used in spectrophotometry. This award recognizes an outstanding achievement in the conception, design, or implementation of instrumentation and/or process control in an area of activity covered by the scope of the ISA's Automation & Technology Department. Carl developed numerous process analyzer applications, using a full range of liquid and gas process analyzers and holds a patent for a unique electrochemical oxygen sensor and technology that speeds response time. He has contributed numerous publications and presentations serving to advance process instrumentation technologies.

We're honored to have Martin and Carl recognized for their contributions to the advancement of automation technologies which help make process manufacturers more efficient.

Tags: ISA | interoperability | HART | Fieldbus | EDDL | spectrophotometry |

November 3, 2006 in Digital Busses, in Interoperability, in Measurement | Comments (0) | Trackback (0)

A 2004 study by the U.S. Department of Energy shows continued global growth for the like Liquefied Natural Gas (LNG) industry as one of the sources to meet global energy demand. Our Micro Motion division recently announced that Coriolis technology is ideal in cryogenic mass flow metering applications like LNG (-153.1 degC). LNG can be stored and transported much more efficiently in a liquid state than in a gaseous state.

I came across a Chemical Engineering magazine article entitled, Flow Measurement in Bitter Cold: How to Use Coriolis Meters in Cryogenic Service which better describes why Coriolis technology works well in the bitter cold of more than -100 degC.

The authors, Emerson’s Tim Patten and Keven Dunphy describe how harsh temperatures pose problems for many flow measurement technologies. These problems are related to mechanical parts, wetted seals, and materials of construction with poor impact strength. And from a measurement standpoint, it’s expensive to keep the cryogenic fluids cold, so they are kept slightly below their boiling points. As the fluid flows past an obstacle such as a valve, flashing can occur. Pockets of gas form in the liquid making flow measurement difficult at best.

Tim and Keven point out that Coriolis technology is well suited since it has no moving wetted parts, nor temperature sensitive materials, and it has the accuracy required to satisfy custody transfer regulations. They recommend careful attention be paid to the pressure drop across the meter to avoid flashing by increasing the meter size. Their rule of thumb:

…the difference between the discharge pressure and liquid vapor pressure at the fluid temperature should be maintained at a factor of at least three times the pressure drop across the meter.

The article also provides tips on density measurement limitations, insulation best practices, and non-linear compensation. These tips apply not only to LNG but other cryogenic applications like liquid helium.

Tags: LNG | liquefied natural gas | cryogenics | coriolis | flow measurement |

October 16, 2006 in Custody Transfer, in LNG, in Measurement | Comments (1) | Trackback (0)

Emerson’s David McLaurin in the Rosemount division presented a workshop entitled, Radar Solves High Temperature Level Application. The application was at a major chemical manufacturer. The refinery makes an intermediate for polyester and other fibers.

The application for level measurement was on a crystallizer unit that had high operating temperature of 230 degC (450 degF.) This unit was a critical path in making the intermediate material. Given these high temperatures nuclear, differential pressure, guided wave radar, other non-contact radar, and weigh cell measurement technologies were considered. Each had issues associated with reliability in this high temperature operating environment.

Radar was chosen as the best option. The manufacturer used a Rosemount Model 5600 non-contacting radar level transmitter with a quartz extended cone. Upon installation there were some issues with condensation on the antenna. This was resolved through insulation. One other issue involved echoes from the agitator blades in the crystallizer unit. Through the software these were masked out.

Comparing the historical trends on the new radar measurement versus the prior nuclear measurement, the radar performed more reliably and more accurately when the unit was operating at low levels.

Tags: radar level transmitter | Emerson Exchange | crystallizer |

October 5, 2006 in Crystallizer, in Measurement | Comments (0) | Trackback (0)

In an earlier blending applications post, I mentioned some of the advantages of online/inline blending over traditional, batch-based blending. It’s a process which crosses many industries including refining, pulp and paper, chemicals/specialty chemicals and food and beverage to name a few.

I came across an article, Optimizing blending operations by Julie Valentine, a refining specialist in Emerson’s Micro Motion division. Julie notes that for refiners, the motivation for changes to the blend process are in improved control, improved measurement, improved analyzers and improved optimization techniques. One of the keys is high performance flow measurements of the raw materials to precisely control their flow rate as they are blended together. The Micro Motion Coriolis flow meters are extensively used for both the raw material and final blending product flow measurement. Their 0.1% accuracy couple embedded advanced control in control systems like the DeltaV system, enable blend optimization to be done within the control system.

In the article, Julie describes a U.K. lube blending plant which switched from a sequential measurement system to a flow measurement based system. This switch enabled the raw materials to simultaneously flow into the mixing tanks, increasing the throughput of the operation. The accurate measurement of the raw materials meant that the blend would be on-spec as it was filling in the mix tank, and shortened the overall mix cycle, again increasing throughput.

The Coriolis meters also provide high accuracy density measurements, which was important since blend component pipe headers are cross connected and this density measurement can quickly spot and notify operators of cross contamination which can affect the quality of the blend.

One other example Julie cites is where the blending optimization for the blend of gasoline allows refineries to make use of the blend components available from production and choose the blend which will produce the required specification at the lowest cost, while also managing inventory levels.

The accuracy of the flow measurement is critical to the blend optimizer. Julie cites a study where poor flow measurement with 0.3% accuracy translates into lost profitability of up to $200,000 per year for a 100,000BPD facility. This is caused by the blend optimizer making the wrong optimization decisions based upon the inaccurate data it receives.

Tags: online blending | inline blending | blend optimization | flow measurement |

September 13, 2006 in Blending, in Measurement, in Refining | Comments (0) | Trackback (0)

Many process manufacturers have flow metering stations where ownership of incoming raw materials, intermediates, and/or outgoing products change. This custody transfer process is common with oil and gas producers, refiners, and chemical/petrochemical manufacturers.

Accuracy is critical since these measurements impact the bottom lines for both the seller and buyer. And, with the introduction in the U. S. of the Sarbanes-Oxley (SOX) Act of 2002, companies are required to put the controls in place to prove the accuracy of these measurements. Other countries have similar regulations requiring these documented proof-of-accuracy processes.

Robert Fallwell, a regional manager in Emerson’s Metco Services business, has written an excellent article, Sarbanes-Oxley audits: coming soon in the July issue of Control Engineering magazine.

Robert shares his expertise on how process manufacturers need to prepare for the SOX auditors. He boils it down to:

…they ask for proof that flow measurements are accurate, that you have procedures to ensure measurement accuracy, and that the plant’s operators, engineers, and production accountants have been trained in the correct procedures for the measurement control process.

The article is filled with advice on how to get ready, where to start in your process, and even 9 steps on how to comply with SOX. In addition to the expertise Robert and the METCO team bring to SOX compliance planning, Emerson has well-established flow technology and calibration management software help assure accuracy over time.

If your business is impacted by SOX or similar regulations, you’ll want to incorporate some of the ideas presented in this article.

Tags: Sarbanes-Oxley | custody transfer | regulatory compliance | flow measurement |

August 8, 2006 in Chemical, in Custody Transfer, in Measurement, in Oil & Gas, in Refining, in Regulatory Compliance | Comments (0) | Trackback (0)