Measurement

A week ago, I highlighted a whitepaper sharing some of the advantages in top-mounting DP flow transmitters in steam applications. The whitepaper's author, Emily Vinella, pointed me to a presentation, What Do You Know About Wireless DP Flow?, which will be given by Emerson's Kyle Nelson and Nathan Stokes at the upcoming Emerson Exchange.

Kyle and Nathan point out that DP [differential pressure] flow measurement continues to be the most often used type of flow measurement, is well understood, and that the measurements are inherently accurate, repeatable, and have quick response times. Smart transmitters dynamically compensate in real-time based on pressure, temperature, density, and flow rate.

Wireless DP flow devices, base on the IEC 62591 WirelessHART standard, open up areas of the plant that may not have been measured because of distance, difficulty, or expense to install wired devices. Four wireless DP flow measurement options are available including integrated wireless on a single variable DP flowmeter, single variable transmitter with a wireless THUM adaptor, separate transmitters with integral wireless to achieve multivariable compensation, and multivariable transmitters with wireless THUM adaptors. The best option is a function of what is currently installed in the facility.

In the presentation, Kyle and Nathan review installation examples for each option. I'll pick the first one, integrated wireless on a single variable DP flowmeter highlight the shared examples. A silicone manufacturer needed to measure 365degF saturated steam flow. These measurements had to be installed in physically challenging to reach locations and wide ambient range conditions, down to -20degF. Other flow measurement technologies had been tried without success. Their solution was to top-mount the wireless DP flowmeters and eliminate $40K of wiring, $15K heat tracing, and $2K impulse lines. By adding these measurements they improved ongoing energy management, reduced operating and maintenance costs, and increased overall safe operations.

A second application was on a steel roll cooling system for a steel manufacturer. They needed better cooling management to accommodate heavier and wider material. Due to a difficult installation location, the cooling system had been manually managed. As larger material was introduced into the manufacturing processes, the defect rate began to increase. The solution was to install four wireless Annubar Flowmeters to allow the water cooling spray to be finally tuned to reduce the defect rate. In addition to the quality improvements, unplanned downtime was reduced, and maintenance costs were lowered from reduced grease system and bearing failures.

Kyle and Nathan describe other applications including diesel and kerosene production measurement, wellhead steam injection, and energy management measurement for environmental reporting. Each had unique challenges that led to the selection of one of the four wireless options.

If you'll be at the Emerson Exchange and have opportunities to add flow measurement to improve your process or address regulatory requirements, make sure to stop by one of Kyle and Nathan's two workshops.

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I connected with Emerson's Don Verhaagen and Emily Vinella and got my hands on a whitepaper on DP (differential pressure) flowmeter installations in steam applications. The whitepaper, Top Mount Installation for DP Flowmeters in Steam Service, describes conditions where top mounting these devices helps to reduce installation costs, eliminates the need and expense for heat tracing, improves accuracy at low range DP measurements, and increases overall reliability.

The traditional installation method is below-pipe mounting, 45-75 degrees below horizontal. This installation method is used to prevent the heat from the process from overheating and inducing transmitter failures. This installation method creates columns of condensate or "wet legs" in the impulse lines running from the process pipe to the pressure sensor ports on the flowmeter.

The whitepaper notes the issues associated with the traditional approach. On startup, the wet legs must be manually filled or else flow measurement errors will occur until the steam condensate refills the legs. Workarounds such as low-flow cutoff configurations in the transmitter are required to avoid these measurement errors that can be 1% of full scale at low range measurements.

Another issue for cold weather installations is the need for steam or electrical heat tracing on the impulse lines to prevent freezing. These are costly to install and difficult to maintain. Also, in corrosive, superheated steam applications, corrosion at the sensing element interface can result.

The whitepaper shares guidance for top mounting these devices by Rosemount DP flowmeter product line and steam application temperature maximums. The Rosemount Annubar products should be mounted 45-75 degrees above horizontal to allow condensate to efficiently drain back into the process pipe. These products are rated for steam applications up to 400degF/205degC.

This compares with 500degF/315degC for those mounted below the process piping. The tradeoff in temperature maximum is improved operation and maintenance. Manifolds and transmitter remote mount options increase the temperature maximums, all the way up to 1200degF/649degC with the Rosemount 585 Severe Service Annubar.

The whitepaper provides similar recommendations on mounting angles and temperature maximums with the 405 Compact Orifice Flowmeter. The 405 can be top-mounted anywhere north of 45 degrees from horizontal, even up to 90 degrees.

The whitepaper authors recommend the top-mount installation method for DP flowmeters used in steam applications where possible to gain the cost savings, improved measurement, and increased reliability.

I recommend giving this whitepaper a read if your plant has steam flow measurement applications.

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I chatted briefly with Emerson's Patrick Truesdale when he was in Austin the other day. You may recall Patrick from several energy efficiency-related posts. He shared with me that he had a couple of presentations that he'd be giving at Automation Week in Houston, during the first full week of October. I asked if I could get a sneak peak to share some highlights with folks who read this blog. I'll highlight one of his papers, De-mystifying GHG Monitoring and Reporting--Achieve Benefits from Compliance, in this post.

The U.S. Environmental Protection Agency's (EPA) new Greenhouse Gas Mandatory Reporting Rules (GHG MRR), also known as 40 CFR 98, came into effect on January 1st of this year and impact more than 10,000 U.S. manufacturing facilities. In Patrick's presentation, he stresses the economic benefits, which can be recognized through improved measurement, accuracy, calibration, maintenance, and recordkeeping.

Some statistics he cites from Methane to Markets' United States Oil and Natural Gas Country Profile are quite eye opening. The methane (CH4) emission losses for 2003 were 353 billion cubic feet (Bcf) for the oil and gas industry and 148Bcf for the production sector. 61Bcf were emissions from pneumatic devices alone.

At current prices around $7 USD / 1 mmBtu, these total emissions represent $2.5 trillion USD. And, by the EPA's carbon dioxide equivalent (CO2e), 1 methane unit is equivalent to 21 CO2 units. Patrick notes that this also translates into 145,000,000 metric tons (mT) of CO2e greenhouse gas emissions.

Oil & gas producers, refiners, and transporters can reduce these emissions with minor improvements in several areas. Patrick believes 20% can be reduced through the switch of high-bleed pneumatic devices to low or no-bleed devices, improved pump seals, meter flange gaskets, and valve packing. This 20% reduction translates into $500 million USD and 29,000,000 mT less CO2e. To put the emissions reduction in context, it is equivalent to the annual emissions output of 10 medium refineries.

Patrick points to technologies emerging to assist with loss control, energy efficiency, and better measurement. These include smart instrumentation with advanced diagnostics, meter verification diagnostics, wireless instruments, low- and no-bleed packing, and vapor recovery units.

Beyond the capture of energy for sale or fuel consumption, these measurements can improve business loss control processes through real-time mass and energy balances, and the establishment of key performance indicators (KPIs). Processes that have been optimized to reduce energy consumption also run with less variability and typically have fewer unplanned shutdowns. Each of these improvements translates into lower operating costs or increased revenues.

Patrick spends quite a bit of time with the regulations and how they affect process manufacturers. If your plant is one of the 10,000+ impacted by these regulations, and if you plan to attend Automation Week, Patrick's talk may be well worth your time. Also, if you're at the Emerson Exchange during the week prior (Sep 27-Oct 1), you can connect with Patrick and folks from the Emerson Climate Technologies team at the greenhouse gas solutions booth in the exhibition area.

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The ever-prolific Greg McMillan is at it again with an article, Wireless - Overcoming challenges of PID control & analyzer applications in the July/August edition of Intech. His article concludes:

Wireless and composition measurements offer a significant opportunity for optimizing process operation. A smart PID can dramatically improve the stability, reliability, and speed of response for wireless measurements and analyzers. The result is tighter control of the true process variables and longer battery and valve packing life.

He authored a companion in depth whitepaper to the article, DeltaV v11 PID Enhancements for Wireless. I'll highlight some of the points Greg shares. The goal of the whitepaper is to describe:

...how enhancements to the PID block for wireless loops in DeltaV v11 improve performance, simplify tuning, and inherently protect against failures. The benefits are also applicable to valves with stick-slip and backlash, and analyzers with cycle times and sample systems used for closed loop control.

Greg first describes the operation of IEC 62591 WirelessHART communications:

The wireless update time termed "default update rate" (refresh time) is the time interval for periodic reporting. The wireless update sensitivity termed "trigger level" is the minimum change in measurement value for exception reporting. To save power, the transmitter goes to sleep and wakes up periodically to check if the change in sensor value from the last value transmitted is larger than the trigger level. When the change exceeds the trigger level or the time since the last communication exceeds the default update rate, then the value is transmitted. The time interval between periodic checks of the sensor is the "triggered update rate" (wakeup time). If only periodic reporting is available, this time interval is the default update rate. Increases in the default update rate and trigger level settings reduce the number of transmissions, which increases battery life.

Wireless communications are fast enough to perform PID control for slower processes with process response times in minutes to hours, such as composition, level and temperature control. Greg explains the problem with traditional PID algorithms with wireless measurements:

...the integral and derivative modes are computed each execution of the PID block. The PID algorithm uses the execution time in the integral and derivative mode calculations. Thus, the reset and derivative contribution calculated by traditional PID may not be appropriate when used with a wireless measurement where the default update rate is significant compared to the process response time. In such cases, the traditional PID will ramp the controller output through continual integral action even though the actual measurement has not changed. The PID is acting on old information. The detrimental effect of integral mode acting on old information is greatest if the process response has largely responded before the next update, which occurs when the process response is faster than the update time or the measurement value has not been updated because of device or communication failure.

He describes the changes made to the PID algorithm to accommodate the wireless inputs:

The PIDPlus computes the integral and derivative mode contributions to the controller output when there is a measurement update and uses the elapsed time between updates in its calculations. Thus, the PIDPlus only acts on new information and considers the observed change in the measurement to have occurred not in just the last PID execution time but over the elapsed time.

The use of a positive feedback network for the DeltaV PID reset calculation enables a further enhancement. If the reset time is set equal to the process time constant, which is the tuning method predominantly used within Emerson, the filter provides a model of the process's exponential response for the integral mode response. The inclusion of the knowledge of the process response eliminates the need to detune the PID to suppress extensive oscillations when the update is much slower than the process response. For these cases, the controller gain can be set equal to the inverse of the controller gain to provide considerably tighter control.

Another consideration in the changes to the PID algorithm is the case of a temporary loss of communications from a wireless measurement or final control device. In this condition, the PID controller provides no additional reset action. Greg notes:

The PIDPlus waits for new information whereas the traditional PID output ramps to an output limit. When communication is restored, the PIDPlus acts on the new information only. The traditional PID sees the effect of the ramp to the output limit that occurred during the loss of communication or loss of valve travel.

Greg shows a number of tests comparing the control loop performance of the traditional PID and PIDPlus. These test cases include flow, static mixer pH, vessel pressure, extruder temperature, vessel pressure, and polymer line analyzer. He sums up his overall findings:

The DeltaV v11 PID enhancement PIDPlus can reduce the process variability from measurement sensitivity limits, valve stick-slip and backlash, and failures for all loops. For loops where the update time is much larger than the process response time, the PIDPlus can dramatically improve the setpoint response (reduce the overshoot, rise time, and settling time) and the load response (reduce the integrated absolute error). For these loops, the PIDPlus eliminates the need to retune the controller to eliminate process oscillations. For integrating processes, such as vessel pressure, the PIDPlus can significantly improve the load response (reduce the peak error and integrated absolute error) if the update time is not too large.

After our July hiatus, Greg and I will be resuming his demo/seminar (a.k.a. deminar) series next week. In these sessions, he demonstrates this control performance in action. We hope to see you at the next one:

PID Control of True Integrating Processes (How to Reduce the Batch Cycle Time for Temperature and pH Loops by 25%) - Aug 11, 10:00 am CDT / 15:00 UTC.

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Update: I've updated the post with the link to the whitepaper in the DeltaV whitepaper section of the Emerson Process Management website.

An engineer came across one of my blog posts and sent me a question about the configuration of a Rosemount 3051C pressure transmitter:

I'm working on a system that uses several 3051C coplanar pressure transmitters. The transmitters were installed to provide flow information via a PLC. The name plate on the transmitters indicate they have a range of 0-xxx [details removed] in H20 for a 4-20 mA signal and the PLC is supposed to convert the signal to GPM with a scaling factor. The value displayed is not representative of the actual flow rate.

According to the reference manual, the transmitter output can be configured for Square Root for flow measurements. The 3051 has two output settings: Linear and Square Root. Activate the square root output option to make analog output proportional to flow.

Is this true for both the 3051SFC and 3051C?

The 3051 SFC transmitters are also used on this system, but the PLC takes the 4-20 mA signal and multiples it before taking the square root.

When Rosemount measurement product questions like these come my way, I turn to my friends on Emerson's Rosemount Technical Support team for answers. A member of the DP [differential pressure] flow specialist team responded:

The 3051SFC is a flow meter assembly. It uses the 3051S transmitter which has a "Scaled Variable" feature which allows us to relate the measured DP to a flow rate, then actually range the transmitter's 4-20 mA output in terms of flow rate. This way you can forget about DP and forget about the square root function, it is all done in the 3051S transmitter, and the transmitter output represents flow rate. Because it would be scaled in terms of flow rate, the transfer function to the 4-20 ma output is left in the linear mode.

The 3051C, can be set to either linear or square root output, but it will always be ranged in term of a DP value, so if you want that range to represent flow, you would set the transfer function to square root output. The 3051C does not offer the "Scaled Variable" feature.

For your 3051SFC, I am a little confused why your PLC takes a 4-20mA signal and multiplies it by a factor then takes a square root. If the unit was configured to output flow then there is no longer a need to square root the value. The 4-20 mA output should already represent the flow scale that it is ranged for.

Could you supply us with the Serial number of the 3051SFC so that we can check our records on how the unit was configured when it left the factory? Kindly provide the full model number as well in order to facilitate our search.

If you have technical questions about your Rosemount measurement products, I highly recommend sending it to the appropriate specialist group email address for answers.

Videos are a great way to share "how to" information. YouTube is great for finding this type of video whether your quest is a home improvement project, learning to play the guitar, or even how to upgrade your Micro Motion RFT9739 transmitter to the multi-variable digital (MVD) technology. The last example may have been a rather abrupt transition, but I think it shows an extremely effective use of YouTube in a business-to-business environment.

Emerson's Camille Stauffer, a technical writer for the Micro Motion family of Coriolis flow and density measurement products, shows the steps required to perform this upgrade in a three-part video series--each under 3 minutes in length. These videos are not demo videos to show the diagnostic benefits associated with the MVD technology (which I highlighted in an earlier post.) Instead, they are made for a technician who will be doing the upgrade. And because the videos are in YouTube, they can be viewed from a PC or mobile device.

For anyone who has assembled home items by referring to a manual, you know that ambiguity is often something through which you must battle. Seeing someone do the assembly on video is usually much clearer. In the case of the RFT9739 transmitter, the video supplements the installation manual.

Here are the three parts of the 9739 MVD Electronics Module Installation video series:

The Micro Motion Online Community continues to grow in membership and participation. How-to videos like these from Camille and team will continue to give people reasons to come back, ask questions, and share their expertise.

Also, if your IT organization is still holding out and blocking YouTube access from your plant or office, hopefully these videos add more reasons to help you in the quest to get YouTube and other valuable social media-related sites unblocked.

A colleague pointed me to a recent ConnectingIndustry.com article, Taking wireless level data acquisition to HART. Emerson's Catrine Bengtsson shared her expertise for this article.

Many plants have legacy control systems with analog input (AI) and analog output (AO) channels that cannot bring in the HART digital signal superimposed on the 4-20mA analog signal. She notes:

Control systems that are HART compatible can interpret the primary variable from the HART field device (HART systems will also be able to get digital data and not just primary variable), but analogue systems will not be able to understand the digital data - for example, the device tag and descriptor fields. The analogue systems are unable to read the secondary or tertiary variables from the field device, if it is a multivariable transmitter, and the diagnostic data.

HART multiplexer devices can route the signals from these devices in two directions--one to the control system I/O and the other to an asset management system. She notes the downside of this approach:

...is not a simple procedure, requiring the rewiring of marshalling cabinets which can pose a risk to current operations and be both time-consuming and costly.

As I highlighted in an earlier post, Thoughts on WirelessHART THUMs, Catrine also notes that WirelessHART THUMs can be used to:

...retrofit on any two or four-wire HART instrument, allowing the device to transmit up to four variables and HART status information at a user-configurable update rate. The data is sent wirelessly, via a gateway, to an asset management system, whereby the information can be interrogated by operators and maintenance staff.

Catrine shares how remote monitoring improves maintenance activities. Without access to the diagnostics, there are:

...huge inefficiencies in the way many process level devices are maintained, including routine checks and preventive maintenance on equipment when it's not needed. If the infrastructure is not in place to communicate the digital HART data to the control room or maintenance area, regular trips to the field may be the only option.

She cites as examples [hyperlinks added]:

...Rosemount 5300 Guided Wave Radar and 5400 Non-Contacting Radar devices can both transmit data to produce an Echo Curve graphic to any host that supports enhanced EDDLs. The Echo Curve is an important troubleshooting tool as it provides full insight to the installation echoes and how they behave over time. Understanding the performance of devices gives a much clearer picture as to when maintenance is required.

Regulatory changes have caused some plants to have to monitor on-line what previously was monitored manually, such as tank overfill protection. In these cases, she notes:

Often, tanks are located remotely and the cost of installing wired devices is very high. Here, wireless presents the obvious solution.

Catrine closes with the point:

Whether you want to install a new measurement point without the high cost of wiring or you would like access to stranded diagnostics and device health information from existing HART instruments, the ability to connect IEC 62591 WirelessHART adapters with process level devices is enabling the full range of HART functions to be accessed in a cost effective way.

Give the article a read if your level measurements do not provide the diagnostic information back to the operations and maintenance staff.

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I came across a great write up on guided wave radar level measurement technology by Emerson's Anna Olander who is based in the Rosemount Tank Radar facility in Sweden. I'll highlight some of the key points I took away from the write up.

The history of radar used in level measurement goes back to the mid-1970s when Saab (whose TankRadar line was acquired by Emerson in 2001) saw a great need for far more reliable and accurate level measuring systems for use in the cargo tanks, compared to existing systems. This recognition resulted in the development of radar level gauge for liquids tanks. The advantage over earlier level measurement technologies was that radar waves are not affected by the atmosphere above the product in the tank, the only part located within the tank is the antenna, and there are no moving parts resulting in greater reliability. The accuracy was also greater because liquid density changes, turbulence, and vibrations did not impact the measurements.

Mechanical level measurement technologies such as displacers have been a mainstay in level measurement for decades. They operate based on the buoyancy of the displacer in the fluid. Fluid density is a key factor in sizing the displacer and determines the stability of the signal, with variations in density affecting accuracy. Build-up on the displacer element also affects accuracy.

In a Guided Wave Radar installation, the GWR is mounted on top of the tank or chamber with a probe extending to the full depth of the vessel. Based on the tank configuration and application requirement there are a number of different probes including co-axial, rigid single, flexible single, rigid twin, and flexible twin probes. There are also probes for aggressive environments and extreme temperatures. These extreme applications can range from -196 degC to +400 degC or 0 to 5000 psig/345 bar.

This technology works on a low energy pulse of microwaves being sent down the probe. When the pulse reaches the media surface, a reflection is sent back to the transmitter. The transmitter measures the time taken for the pulse to reach the media surface and be reflected back and an on-board microprocessor accurately calculates the distance to the media surface using time-of-flight principles.

GWR is recommended over non-contacting radar in most chamber applications because it is unaffected by the size and shape of the chamber and is better at managing shorter measuring ranges. Measurements can be made below the top liquid or foam surface, as the probe penetrates the liquid. It can also measure the interface level in separators and provide true bulk surface level measurement in boiling, turbulent or frothy liquids.

Anna references some common applications for GWR level measurement including gas/oil and oil/water separators, distillation columns, liquefied gases and Freon's, power and industrial utility water level to name a few. She sums up the advantages as being more accurate, reliable and trouble-free measurement of liquid surface and interface levels. Measurement is unaffected by changing density, temperature and pressure, as well as condensing vapors or liquid drops attached to the probe, and provides reliable measurement of turbulent, boiling liquid surfaces and low reflective applications such as liquefied gases.

When I was at Emerson's Micro Motion facility in Boulder last week, I had a chance to meet product line business manager Tonya Wyatt. She recently did a quick video for the Micro Motion Online Community to announce a new transmitter with multi-variable digital (MVD) technology.

What's neat about the 4:33 video is how Tonya explains the background for the Model 9739 transmitter with MVD technology based on customer feedback. The existing transmitter, the RFT9739 has the analog electronics. It been used by process manufacturers for 20 years. The MVD technology, based on digital signal processing (DSP), improved the transmitter by doubling the turndown ratio, or measurement range of operation. And, as with most things that have moved from analog to digital, accuracy was also improved and greater noise immunity provided more opportunities for operation in electrically noisy environments.

Tonya shares the feedback that even with the improvements, many process manufacturers did not want to upgrade because the form factor of the RFT9739. At 1:30 in the video she describes the feedback that everything in this form factor is front accessible, the unit is wall-mountable, and its ruggedness is a good fit for truck applications

In spite of the popularity and longevity of the RFT9739, Tonya explains the realities that hardware manufacturers face in electronic parts obsolescence. With Moore's Law inexorably driving the price/performance curves of electronic components, it's a challenge to find new components to fit a design conceived long ago.

At 2:24, Tonya shares the results of the questions they asked customers given the reality that the RFT9739 could no longer be made at some point in the future due to parts obsolescence. Process manufacturers wanted the MVD technology for the improvements in diagnostics, accuracy, turndown ratio, and noise immunity, but they wanted to keep the form factor that was friendly to work with. They also did not want to have to change the conduit connections or rewire and be able to upgrade in place the analog electronics over to the MVD electronics.

At 2:50, Tonya highlights that this listening went into the design of the Model 9739 transmitter with MVD technology. For existing installations, an upgrade replaces the power supply and electronics without disturbing the wiring.

Two thoughts come to mind after watching this video. The first is that as the Micro Motion Online Community grows, more of this dialog between process manufacturers and Micro Motion marketing and technologists will occur on a daily basis to improve designs across all of the products. Ideas can be put out, discussed, argued over, and improved through this public communications medium.

The second is that these quick YouTube videos help convey the whys in product developments better than most other traditional forms of communication. What do you think?

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Update: Eoin Ó Riain reports on the 9739 transmitter over on his Read-out Instrumentation Signpost blog.

I wanted to highlight a new Emerson Process Management blog, Analytic Expert. This blog is a team effort by Rosemount Analytical product and application experts. Here's background on the four bloggers listed on the About Us page.

Jim Gray has worked as an application manager for more than 20 years. Fifteen years ago, his role expanded to include support and development for HART, Fieldbus, and Profibus devices and software. I've highlighted Jim's expertise a couple of posts here on this blog. In his introductory post, Let's Talk Wireless, he shares the purpose behind the Analytic Expert blog:

The purpose of this blog is to discuss the application of liquid and gas analyzers and systems. It will also serve to introduce new approaches to these applications made possible by new developments in analyzer hardware and software. It is hoped that we can begin a conversation that will provide you with new insights that will make it possible to apply analyzers more effectively, reliably, and at a lower installed cost. Because we cover a large range of topics, the blog will not always be written by the same person as we want to include experts to comment on their own subjects. You will get to know all of us over time. We want to hear from you with comments and suggestions on what you would like us to cover.

Daniel Benitez helps to drive research and development of analytic products, as well as oversee global marketing. Daniel tackles the subject of gas chromatograph cost of ownership in his first post.

Dave Joseph, whom you may recall from several pH-related posts, supports the "heavy" industries such as chemical, refining, pulp and paper, and metals and mining in his role as senior industry manager. Analytical products are used in common situations such as neutralization and leak detection, and very specific applications like removing free fatty acids in biodiesel production. His first post, Calibration Got You Down? is about pH sensor maintenance.

Doug Simmers has been the expert behind several combustion-related posts on this blog. He is the worldwide product manager for the Rosemount Analytical line of combustion analyzers and has spent 27 years providing process controls and instrumentation to the power, refining, and pulp and paper industries.

It's great to see the newest bloggers in the Emerson Process Management group already finding their voice. I don't think I could have gotten away with referring to Doug as a "Combustion Geek", as he has done in the most recent post, The Combustion Geek. In the post, he tackles some of the mistrust issues around analyzers. He observes:

...reasons for this mistrust that can be overcome by better understanding of how they work, and what to expect from them. For example, unlike many other measurements, most gas analyzers can be calibrated automatically on-line with the process running, with calibration gases sequenced to the sensors and adjustments made via microprocessors.

If you have liquid and gas analytical instrumentation in your plant, you will want to subscribe to the Analytic Expert RSS feed to be alerted when new posts by Jim, Daniel, Dave, and Doug become available.

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I received a question a few days ago about flow measurement and wet gas. Here is a paraphrased version of the question:

The meter would be used to measure gas in and out of storage. The gas may be wet--depending on pressure and temperature. I do not know yet how wet it can be. Ultrasonic meters have been tried in the past and sometime have issues if there is too much water in the gas. How much is too much and is there a general guideline for gas wetness that applies to these meters?

I turned to Emerson's Karl Stappert who has experience with a number of flow measurement technologies ranging from Ultrasonic to Coriolis effect. I thought his answer was the makings of a great blog post so I thought I'd share it with you.

The "wet" is of course liquids of varying levels that tend to collect on the walls of the piping at any velocity. The problem is that regardless of liquid loading levels, they will build up in low-level areas of the piping at low flow velocities and they get swept out and whipped-up back into the flow stream when high velocity flows are reintroduced. Liquids can collect in the USM [ultrasonic meter] transducer ports bridging the space between the transducer and USM meter body causing the ultrasonic transducer to fail. USMs such as the Daniel JuniorSonic, which has its transducers located at the top of the meter pointing down, will mostly eliminate the liquid bridging on the transducers.

This design mostly eliminates the liquid bridging concern, but there still exists the potential for intermittent failures when the flow transitions from low velocity to high and sweeps liquids up that have collected during the low velocity timeframe. Liquids that are entrained into the gas stream will cause refraction of the ultrasonic sound wave and may degrade signal quality causing some ultrasonic sound shots to fail in a batch of shots. However, failure of all shots in a batch is a rare occurrence and likely only intermittent if ever. It is not possible to totally alleviate these intermittent conditions regardless of liquid load in the flow stream. This is due to the liquid collection issue at low velocities and potential piping configuration issues.

A meter and meter tube inspection and cleaning program should be employed to ensure the accuracy of the meter over time. Also, with the increasing flow capacity of Coriolis flow measurement, this technology can be considered for these slightly wet gas conditions.

Changing wetness conditions is a challenge in gas flow measurement. Both Ultrasonic and Coriolis measurement can be successfully applied. It's important that any piping issues be addressed to avoid liquid collection areas upstream of the flow meter and that that the maintenance program monitors for wet conditions.

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In my Emerson Process Management RSS news feed was news of a new wireless vibrating fork liquid level switch from Emerson's Rosemount measurement team. Not being familiar with this technology, I connected with product manager, Kevin Cullen. I asked him about this technology and how it fits in the world of liquid level sensing applications.

He first explained that there are a number of liquid level sensing technologies in addition to vibrating fork including ultrasonic, capacitance, and electro-mechanical. To understand the principle of operation, I turned to the Rosemount 2160 data sheet:

...designed using the principle of a tuning fork. A piezo-electric crystal oscillates the forks at their natural frequency. Changes to this frequency are continuously monitored.

The frequency of the vibrating fork sensor changes depending on the medium in which it is immersed. The denser the liquid, the lower the frequency. When used as a low level alarm, the liquid in the tank or pipe drains down past the fork, causing a change of natural frequency that is detected by the electronics and switches the output state to a Dry condition.

When the 2160 switch is used as a high level alarm, the liquid rises in the tank or pipe making contact with the fork, causing the output state to switch to a Wet condition.

The output state, along with other parameters, are regularly transmitted over a secure wireless connection to a Smart Wireless Gateway.

Kevin noted that these vibrating fork liquid level switches come in a range of models to address applications from very simple ones rated for unclassified areas to ones like the 2160 with advanced diagnostics rated for environments with temperatures from -94 degF (-70 degC) up to 500 degF (260 degC) and pressures to 1450 psig (100 bar g). This sensing technology is largely unaffected by liquid turbulence, foam, vibration, solids content, or coatings on the tuning fork. An adjustable delay for turbulent/splashing applications prevents false trips of the switch.

Kevin shared some of the advanced diagnostics available to spot problems with the device or surrounding process. These included external damage to the fork, internal damage to the sensor, coating buildup on the fork, and excessive fork corrosion. Alerts can be set to notify operations and maintenance of these conditions before they impact the process with a false trip condition.

The addition of WirelessHART communications is the part that Kevin said excites many process manufacturers. Most every plant, production field or platform, or mill has a need for level measurement in areas that are currently too costly to measure using wired switches, due to either inaccessibility or economics. One application example is using the 2160 for overfill protection in a tank that did not have convenient instrumentation wiring access.

Not knowing much about vibrating tuning fork technology before I started this post, I learned a lot from Kevin. I hope if you were similarly not well versed, that you did too.

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I'm checking in over at Emerson's Micro Motion Community today to see how the growth of this community is coming along. In the post, Communities to Find Answers and Solve Problems, I shared some statistics on the size of the Micro Motion community. There has been growth in members, friendship bonds, posts, comments, videos, and more since last report.

A view of the What's New? Page shows quite a bit of activity over the past two days. And the timestamps show that participation is happening around the clock, so likely the community is either global or there are a number of night owls who love Coriolis flow and density measurement late night discussions. My guess without digging into it is the former.

A good example of a recent post:

I need to know if anyone has information about Coriolis in Flow Measurement of Heavy Oil Petroleum 9 to 11°API, with high viscosities.

Emerson's Pat Page, a member of the Micro Motion sales team responded:

We continue to have success in measuring heavy API gravity crudes. If you would like to see performance for a particular application, send me the flow details and we can provide flow calculations with pressure drops and accuracy.repeatablilty data. [email address]. Need to know what the flowing viscosity and temperature will be.

One of the things you'll notice as you look through the various forum discussion threads is high participation from the Micro Motion team. This is one of the success factors for communities centered around products and applications. In some threads, process automation professionals have offered strong opinions on what they don't like or believe is missing from a product. This feedback and ongoing connection between customers and the Micro Motion team is just what Micro Motion president Tom Moser was seeking in his February Intech magazine Executive Corner article, Online collaboration: A win for all of us. In the article, he cited an Aberdeen Group study, which noted:

...organizations realized a 93% improvement in their ability to capture consumer insight that drove a new product or service development. In addition to contributions to new product development, these organizations achieved an estimated 63% customer service cost reduction and 82% improvement in identifying and reducing risk to their brands.

Although this community centers around Micro Motion Coriolis flow and density measurement, the videos area currently has 9 videos including videos showing Rosemount pressure measurement devices and DeltaV SIS safety instrumented systems. Applications often span many products and technologies, and videos are great way to quickly show how technologies can be applied to solve problems.

I saw a first peek of this community at the 2009 Emerson Exchange from Mike Tongwarin, who leads this community. It has come quite a ways from its official launch in November 2009. The community will continue to grow if the current ingredients remain intact. These ingredients include the members continuing to find value in the questions they ask and the answers they give, the Micro Motion team continuing to have strong senior management support, and community managers like Mike continuing to inject energy and enthusiasm to foster wider and deeper participation.

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ControlGlobal.com hosted a recent whitepaper, Guided Wave Radar vs. Differential Pressure Transmitters for Liquid Level Measurement. The paper was developed by an automation supplier, which offered guided wave radar level measurement devices. The message seemed to be that the newer technology, Guided Wave Radar, could displace much of the more established, differential pressure level measurement applications.

Since Emerson offers both differential pressure (DP) and Guided Wave Radar (GWR) technologies, I turned to Emerson's Lori Egbers, a Rosemount level measurement application specialist for her thoughts. She shared some background information that looks at the various level measurement technologies and their best application fits.

The choice of level measurement technologies is vast. This list includes both manual and continuous measurement methods such as DP, tuning fork, bubbler, dipstick, capacitance, ultrasonic, radar, sight glass, nuclear, displacer, gage glass, ultrasonic gap, hydrostatic, and weight. Obviously, for so many level measurement technologies still to be in use, it stands to reason that they have advantages and limitations in application.

One area of consideration is the application condition. Some of these conditions include levels of steam, vapors, dust, liquid density changes, pressure changes, liquid viscosity, abrasiveness, foaminess, corrosiveness, temperature range, and amount of agitation. Another area of consideration is the physical installation. Agitators, blades, baffles, and other obstructions in the vessel where level is being measured will determine the subset of available technologies.

Lori notes that both DP and GWR level measurements are considered contacting since they "touch" the process. Other level measurement technologies in this category include capacitance, magnetostrictive, and displacer. Examples of non-contacting level measurement devices include radar, ultrasonic, laser, and nuclear.

A ControlGlobal.com article, Beginner's Guide to Differential Pressure Level Transmitters offers a great description on how DP level measurement works:

Differential pressure level measurement technology infers liquid level by measuring the pressure generated by the liquid in the vessel. For example, a water level that is 1000 millimeters above the centerline of a differential pressure transmitter diaphragm will generate a pressure of 1000 millimeters of water column (1000 mmWC) at the diaphragm. Similarly, a level of 500 millimeters will generate 500 mmWC. Calibrating [ differential pressure transmitter for 0 to 1000 mmWC will allow it to measure water levels of 0 to 1000 millimeters.

The advantages of differential pressure in measuring levels are that it's reliable (no moving parts), simple, and well understood. Its use is flexible in measuring level, density, liquid interface, and mass. It can be applied in vessels with agitation and foam. DP measurement can be used in vessels with internal physical obstacles. Diaphragm seals extend DP measurement to applications with high temperatures, corrosive liquids, dirty or viscous liquids, or sanitary considerations.

DP level limiting factors include measurement errors from changing density, temperatures beyond 600degF, trickiness of high-vacuum applications, highly corrosive processes, highly abrasive processes (potentially damaging diaphragms), and liquid-only measurement. From a physical installation standpoint, the bottom-mount technology is a potential source of leakage and DP measurement often requires two taps.

How the Guided Wave Radar technology works is:

...based on Time Domain Reflectometry (TDR) principles. Low power nano-second-pulses are guided along an immersed probe. When a pulse reaches the surface, part of the energy is reflected back to the transmitter, and the time difference between the generated and reflected pulse is converted into a distance, which calculates the total level or interface level...

Lori shares many GWR application advantages including direct measurement of solids and liquids, effective interface measurement, no moving parts, and no impact to changing densities/dielectrics/conductivities. It's tolerant of foam, turbulence, heavy vapors, and condensation. From an installation standpoint, it's a better fit for small tanks, tanks with difficult geometries, small connection sizes (< 2"), and threaded nozzles. Finally, GWR is proving to be an easy replacement technology for displacer and capacitance level devices as it is very easy to swap by using the same connections. GWR is better than non-contacting radar measurement technologies for applications with heavy vapors, such as anhydrous ammonia.

GWR is limited from applications with agitators, blades, and baffles which may interfere with the probe placement. Coating on the probe from very sticky fluids may affect the measurements. If the level has an emulsion instead of clearly defined interfaces between separated liquids, the readings may not be accurate or will require more care in configuration. Finally, for taller (>50 ft) solid measurement applications, the height and associated pull forces need to be evaluated to determine suitability of GWR measurement.

I know that these are a lot of things to consider. Clearly, there isn't one specific level technology, which is appropriate in every tank. It's important to carefully consider tank and process conditions to ensure a good technology match. To help you select the right level measurement technology, Lori pointed to a Level Selection Guide. It shares the advantages and limitations of these and other level measurement technologies to help you find the best ones for your application.

MP3 | iTunes

I caught up with Emerson's Tom O'Banion to get the latest on the U.S. Environmental Protection Agency (EPA) Mandatory Greenhouse Gas (GHG) Emissions Reporting Rule. Tom is the Director of the chemical industries in the Micro Motion Coriolis Flow & Density Measurement business.

Tom shared some issue raised and discussed from the Mandatory GHG Reporting Rule workshop at the National Petrochemical & Refiners Association (NPRA) meeting in Houston earlier this year.

Tom noted that refiners had a great number of questions about the rules and the actions they needed to take. These GHG rules became effective at the end of 2009. On the rule's milestones, the EPA states:

On September 22, 2009, the rule was signed by the Administrator and was published in the Federal Register on October 30, 2009. The final rule goes into effect December 29, 2009. As discussed below, the rule requires reporters to begin monitoring on January 1, 2010. The first reports will be due on March 31, 2011.

Approximately 10,000 U.S. sites are affected--representing an enormous safety, health and environmental set of considerations with which plants and mills must contend. During the workshop, the EPA clarified a question about the use of mass flow measurement devices for liquid fuel flow measurement, responding:

Fuel flow meters that measure mass flow rates may be used for liquid fuels, if the fuel density is used to convert the readings to volumetric flow rates.

Perhaps the most discussion centered on the use of mass flow measurement beyond liquids. Currently, the EPA restricts mass flow measurements to liquids. The American Petroleum Institute (API) members wanted a clarification from the EPA on the suitability for mass meters in measuring flows of gaseous streams. The API believes gaseous streams mass flow measurement should be permitted and would like to see this changed. Measurement of gases right now needs to be performed with flow meters measuring differential pressure (DP), total pressure, and temperature to apply pressure-temperature compensation to the measured flow rates.

The EPA regulations are written to leverage "consensus standards" such as API, AGA, ASME, etc. In the various sections of 40 CFR part 98, all of the Coriolis standards are referenced (AGA-11 / API MPMS Ch 14.9, ASME PTC, etc.) There is an API Task Group forming to write a new API document that will describe flow technologies for use in GHG fuel gas applications. It will be all the major technologies such as DP/orifice, vortex, turbine, Coriolis, thermal, etc. The request for this task group has been approved and the membership is being formed.

On a question about meter calibration error exceeding the rule's 5% performance specification, the EPA indicated that if the error exceeds 5% to use the best available monitoring method (BAMM) and an extension could be granted for the remainder of 2010 if an extension was requested by April 1. The meter would need to be modified or replaced before the extension expired to comply with the rules.

Tom shared that Meter Verification is of great interest to refiners and other process manufacturers impacted by these regulations. Meter Verification is allowed under the EPA approach of following "manufacturer recommended practice" and is both a labor savings as well as a safety benefit to not have to break the line--even orifice measurement must be physically inspected every 3 years.

One only has to look at the Frequently Asked Questions page to note the complexity and issues refiners' and other process manufacturers' face with compliance. Tom suggests visiting the GHG Compliance area of the Micro Motion Community to connect with others to ask and answer questions about the measurement and collection of the information required for GHG reporting.

There is also a Greenhouse Gas Compliance Readiness section on the Micro Motion website that highlights the issues and solutions to meet these regulations.

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Neural networks, not the ones in our brains, but the ones that came out of the artificial intelligence research, began back in the 1940s. This advanced process control (APC) technology has been used in the process industries for many years for applications ranging from virtual sensors to end of batch prediction. Neural networks have been discussed in numerous ModelingAndControl.com blog posts. Several software packages, such as DeltaV Neural, exist to build these neural networks applied in process automation-related control strategies.

I received an email yesterday from an engineer trying to predict quality for a product made in his manufacturing process. Their current way to do this was to get quality data from lab samples drawn every 4 hours. Obviously if quality problems are not discovered until the results are back from the lab analysis, it can impact 4+ hours of production. The person asked me what historical data collection frequency should be used to build the neural network model. In his case, he was using DeltaV Neural.

I turned to Lou Heavner, whom you may recall from an earlier neural network-related post. Lou had a great response and I asked if I could highlight some of it here.

Lou opened:

The sample frequency is related to the process dynamics. Initially you can make an educated guess and later revise if necessary. The Neural model is based on observing inputs that will affect the modeled output. There is likely to be some delay between when an input is observed and when the output is affected.

For example, if I had a conveyor with a 10-minute transit period from the point at which some measurement is made (e.g. temperature) and that measurement is important to modeling the output, say quality (e.g. moisture) from a sample port in a downstream hopper. And, the residence time in the hopper from the conveyor to the sample port is 15 minutes--I would have a sample delay of approximately 25 minutes. This is the time between when the material's temperature was measured and when it was extracted as a lab sample.

We refer to this in DeltaV as the time to steady state (TSS), although it is more accurately described as the process residence time. DeltaV Neural divides the TSS into 50 equal intervals and reads all inputs at that frequency. In this example with TSS = 25 minutes, the data frequency would be every 30 seconds. The sampling frequency of the DeltaV Neural block can be faster, but should be no slower. Having the Neural block update once per second may put some additional load on the controller, but that is the only penalty of setting the sampling rate faster.

If you use a Lab Data Entry block to enter the lab results, the Neural block will "poke" the lab data where it belongs in the file. In truth, it isn't poking as much as it is defining a delay. It is important to get the lab data timestamp right to build a successful model. That is why we go to such pains to get the delays and sample times correct. So the lab data needs to be tagged with the time stamp corresponding to when the sample was extracted. This may be and in fact probably is different from the time the sample was scheduled to be extracted, or when the lab analyst performed the analysis, or when the sample was reported, or when the historian was updated.

If you use the Lab Data Entry block and select the correct TSS, there should be no problems building a Neural model due anything related to sampling frequency. If you are unsure of the correct TSS, it is usually better to overestimate than underestimate. The biggest problems are models where some variables have a very long delay and others have a very short delay. In order to see the effect of the variables with the long delay, you may not have the granularity you need on the variables with a shorter time delay. You will need data that is accurate and that exhibits typical process variability, since the model is trying to correlate various model inputs with the model output.

Lou also passed along some guidance when attempting to build the data set for use in the creation of the Neural Network in the offline mode:

It sounds like you are limited to developing an online Neural model using historical data. There are many pitfalls to watch out and avoid. This is called data mining and sometimes success is simply not possible. The same rule for data frequency applies. It doesn't matter if you are using data from 1 hour, 1 shift, 1 day, 1 week, or 1 year. If the data frequency is slower than the real process TSS, the best you can do is create a steady-state model which is probably going to suffer in accuracy unless the process is truly at steady state and has been for 1 TSS prior to each lab sample.

Next, historical data is often conditioned, compressed, averaged, or in some way filtered. This will weaken the correlation and make a poorer model. Ideally, the process inputs should be raw snapshots. When you collect lab data, it is often collected at irregular intervals. The sample schedule may call for samples to be taken at 6:00am every morning, for instance, but the actual sample time may vary (depending on what the sample taker is doing) from somewhere between 5:30 and 6:30.

What I typically do is import my process data (Neural inputs) from the historian into Excel. Neural will find the correct time delays, so you do not need to worry about that. I create a separate column for the lab data. I populate that column with the word MISSING in each row. Then I copy the lab data into the position that corresponds with the time the sample was extracted. Neural ignores words and uses only numeric values. Another thing I do is look for any bad or missing values from the historian and replace those cells with the word BAD or MISSING. Once I have the values correctly saved in the spreadsheet, I can save it as a tab delimited value (.txt) file. Make sure the header information is correct and you are ready to train.

There is a mathematical minimum requirement for the number of lab samples required to build a model and it is related to the number if model inputs. From practical experience, I find that a model with 10 inputs will require at least 100 lab samples and all of those samples must show some variability. With 20 inputs, you would need to at least double and possible triple that amount. With lab data collected every 4 hours, you would probably need about 5 weeks' worth of data and with a TSS of 25 minutes, the process data would need to be 30 second data. You should also verify the resulting Neural model against a completely different set of data to assure yourself you have a reasonable model.

If you're building neural network models for property estimation, virtual sensors, time prediction, or other applications, I hope some of Lou's experience serves as a shortcut to your successful implementation.

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In our world where email inboxes and sent items folders overflow with both spam and valuable information, it grows harder to find what we need. The trend to rely on our professional networks to find answers and solve problems continues to grow.

In my role at the surface of the Emerson organization, I subscribe to many of the automation communities in LinkedIn to get a feeling for the issues being discussed and how Emerson experts might help. Some of the ones I follow include:

• DeltaV
• ISA
• Automation
• Automation & Control Engineering
• Automation Engineers
• Automation World
• CONTROL Global

It's not an all-inclusive list, just some I follow and ones in which I receive daily summary emails. These groups have varying degrees of participation and mostly are not being led by active, focused community managers.

From an automation supplier-led community standpoint, the Micro Motion Community is a good example. The community has grown to 763 members, has connected 1742 friendship bonds, has 275 posts with 124 comments, includes 6 videos, and mentions 21 events to date. The community has strong support from the Micro Motion organization and is led by online marketing manager, Mike Tongwarin.

Mike has posted two of the videos, Micro Motion Launches Online Community and Micro Motion SMART Meter Verification. The latest smart meter verification video is hosted in YouTube but also viewable within the community. I imagine more will continue to be added over time.

The community also has a blog area where community members have posted a few blogs. Some of these posts include Greenhouse Gas compliance, Vapor Recovery, and a kickoff Let's get started! post.

As with most communities, growth occurs over time if the people who visit find value and share the site with their peers. It boils down to whether the particular community helps find answers and solve problems more quickly than by other means.

I know that Mike and the team are committed to add the necessary energy into the Micro Motion Community to make sure the experience for those who visit is indeed valuable. I also look forward to sharing more on-line communities around Emerson Process Management as they bloom.

MP3 | iTunes

Metering imports, exports, and allocations is a serious matter for plants. If the metering systems in your plant under-measure custody transfer of intermediates and final products to another business, profits are lost. Over-measure and your business shortchanges your customers, which can damage your reputation and expose you to legal liability. Given its importance, custody transfer has been the subject of many posts here on the blog.

Lots of factors can impact the accuracy of your metering system including system design, equipment selection, maintenance and upkeep, and the skills of your metering staff. I caught up with Emerson's Donald Angus who is a member of the METCO services team, based in Aberdeen, Scotland. METCO works with process manufacturers to provide total metering services to operate, maintain, and manage metering systems to ensure their accuracy. Some process manufacturers have concluded that metering skills are not a core business function, so they look to service providers such as METCO to perform this function.

Donald shares that key performance indicators (KPIs) are often established with risk/reward terms. If the metering performance does not meet the agreed KPIs, the service team does not get paid. These contracts typically include metering maintenance/recertification, metering data validation & reporting, mis-measurement reporting, spares management, service coordination, and metering personnel management.

The METCO team has more than 70 on-site metering specialists and more than 40 consultants, auditors, and engineers based in Aberdeen. Given these risk/reward-based contracts, the skill development of this team is a critical activity. Scotland has a rigorous competency program, Scottish Vocational Qualifications (SVQs), designed to benchmark individual skills against national standards of competence. It's described:

Scottish Vocational Qualifications (SVQs) are based on standards of competence (National Occupational Standards) that describe a candidate's ability to work in real conditions - having an SVQ is a kind of guarantee that a candidate is competent to the standards that the SVQ is based on. The National Occupational Standards (NOS) are developed by Sector Skills Councils (SSCs) on behalf of business and industry - as part of the development process, an SSC will liaise with employers within its sector.

The METCO metering team is certified to level 3 in measurement and is the only center in the world to offer this level of measurement certification.

Custody transfer metering falls under the jurisdiction of regulations such as the U.S. Sarbanes-Oxley act. Accurate and repeatable measurements are critical to compliance with the law and avoiding civil and possible criminal litigation. Having highly competent metering specialists as part of the plant's extended team might make economic sense based on the regulatory environment in which your plant operates.

MP3 | iTunes

You may recall Emerson's Bill Zhou from his demo video pieces here on the blog. I told him to be on the lookout for unscrupulous talent agents who'll want to whisk him away to Hollywood. Bill pointed me to a HART Communications Foundation announcement of Mitsubishi Chemical Corporation selection as 2009 Plant of the Year. Their use of HART communications helped deliver strong operational and financial results:

Diagnostic parameters that help detect signs of an abnormal situation or degrading performance are difficult to obtain with simple handheld devices because they require a time-consuming, manual, step-by-step approach," says Takayuki Aoyama, team leader, instrumentation group, Mitsubishi Chemical. "HART technology made it possible to access this data without manual operation. This made it much easier for us to gather data and detect abnormal situations from field devices and has reduced maintenance costs by 10 percent.

Bill and Takayuki presented at the 2009 Emerson Exchange with a session titled, Process Profiling: Investigation and Prediction of Process Upsets with Advanced Diagnostics. They share how the statistical process monitoring (SPM) technology found in the Rosemount 3051S measurement devices were used to measure flow through an orifice plate from a Naphtha tank to a series of furnaces. With the success of detecting plugs in their impulse lines, they expanded the SPM usage into other applications where the process was problematic.

The SPM diagnostics helped to quickly identify issues such as inadequate straight pipe length in DP flow, plugged manifold, compressor vibration issues, and even when strong winds affected the process.

Using the diagnostics to solve these conditions and spot problems early helped this award-winning plant to shift from time-based to condition-based maintenance and deliver quantified business results.

The president of Emerson's Micro Motion Coriolis flow & density measurement business, Tom Moser, has a great article in the Jan/Feb edition of ISA's Intech magazine. The executive corner article, Online collaboration: A win for all of us, is a strong call to action for process automation suppliers and process manufacturers to take advantage of social media (a.k.a. Web 2.0) to improve listening, research & development, and the way we learn and interact.

Tom frames the opportunity:

Today, as consumers, we have the opportunity to evaluate, share, research, and comment on any product or service online. Consumers can change the course of a new product introduction and influence what companies will develop and sell to us in the future. While this might put us outside of our traditional comfort zone, one thing is for certain--we all need to accept it and embrace it.

Through social media applications like Twitter, LinkedIn, Facebook, blogs, RSS searches, etc. companies can immediately improve their listening skills. Tom describes in an Aberdeen Group report on listening to online conversations, that organizations:

...realized a 93% improvement in their ability to capture consumer insight that drove a new product or service development. In addition to contributions to new product development, these organizations achieved an estimated 63% customer service cost reduction and 82% improvement in identifying and reducing risk to their brands.

With these types of ROI figures, it's understandable how social media initiatives in business-to-business (B2B) companies have moved beyond the organizations' grassroots levels into the executive management levels.

Tom notes that the tools themselves are not costly. What does consume resources is the organizational commitment to the time required to regularly track, participate, and use the flow of information that improved listening provides. Taking advantage of the insights that users of your products and services share can be the differentiation your company offers versus your competition to grow your business.

Beyond better listening, Tom enumerates other benefits such as closer connections, tapping ideas/solutions more easily, better best practice sharing, faster access to information, improved personal development, and more.

I highlighted in an earlier post, Join the Micro Motion Online Community, how the Micro Motion team is fully embracing Tom's ideas with an on-line community around Coriolis flow and density measurement. If you have these measurement devices or have the interest to learn more about the technology, this community is a great place to ask questions and learn from experts.

In the article, I couldn't agree more with Tom's closing thought:

Social media is dramatically changing our behavior as end consumers. In the B2B world, it is time to fully leverage the capabilities that Web 2.0 enables. We will all win.

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Update: Welcome, readers of the What's Working in Marketing blog! We appreciate any thoughts you have on collaboration.

Update and bump: Greg's article is now live on the ISA.org InTech website. Below is the original Dec. 15, 2009 post.

I received an advanced copy of an article ModelingAndControl.com's Greg McMillan has recently completed, Exceptional Opportunities for Smart Wireless pH and Conductivity Measurements. In the article, he summarizes these opportunities:

...for inferential measurements, solution temperature correction, efficient calibration, noise minimization, and predictive maintenance by taking the advantage of smart features and wireless communication.

On inferential measurement, Greg notes that the connectivity, intelligence and portability of wireless conductivity and pH measurements increase the possibilities for successful inferential measurement creation. He writes:

The availability of the primary process variable (pH), and the auxiliary variables (milliVolts, temperature, reference impedance, glass impedance, and RTD resistance)... for a smart wireless pH transmitter, facilitates the monitoring of sensor performance besides developing relationships for solution temperature compensation, solvent concentration, and CO₂ loading.

Inferential models developed within the automation system neural network algorithms use conductivity, pH, and temperature inputs to better predict solvent concentration and CO₂ loading.

With respect to temperature compensation, Greg observes that the standard temperature compensation in pH measurement as defined by Nernst equation does not account for actual solution pH changes with changing temperature. Additional solution temperature compensation in smart pH transmitters is beneficial for many applications. Greg shares:

Lab tests where the pH and temperature of the sample are varied to cover the operating range are required to quantify the effect of weak acid and base dissociation constants on solution pH. Smart wireless pH transmitters allow the user to develop, document, and integrate the solution temperature compensation results from lab tests.

Most automation engineers have faced issues with electromagnetic interference (EMI) causing noise on their process measurements. For pH measurements, spikes can be caused by ground loops or the operation of motors and variable speed drives. Wiring to the instrumentation can act as an antenna for this noise. Wireless devices avoid the EMI issues that wiring induces.

Many pH applications are difficult, due to electrode coating, plugging, and aging that can occur in days or weeks. Wireless lab and field pH and conductivity measurements in a lab process sample:

...creates interesting opportunities for predictive maintenance on when to clean or replace electrodes.

The technology team envisions how these smart pH and conductivity measurements could be enhanced with:

...a model for a particular sensor and run a simplified principal component analysis (PCA) within the transmitter to detect a failure.

The article shares specific examples of the team's work with the University of Texas and their absorber for CO₂ capture and distillation column for solvent recovery. I'll update this post when I know when and where the article will be published. Until then, I hope this gives a brief sample of some of the innovations occurring on the pH and conductivity measurement and control fronts.

MP3 | iTunes

You only have to do a Google News search on EPA greenhouse gas reporting rules to know this is a large issue on the minds of U.S. process manufacturers.

The U.S. Environmental Protection Agency (EPA) has released a mandate, 40 CFR Part 98 requiring the monitoring and reporting of greenhouse gas (GHG) emissions effective January 1st 2010. These regulations are more than 1200 pages in length. Emerson's Micro Motion division has highlighted some of the key considerations in an EPA Greenhouse Gas (GHG) Reporting Rules FAQs web page. Tom O'Banion, chemical industry director for the Micro Motion team, shared some of the key issues these regulations introduce.

The most significant parts of the new regulations for most manufacturers apply to the emissions of carbon dioxide (CO₂) and nitrous oxide (N₂O) resulting from the burning of fossil fuels. Methane (CH₄) is another source typically caused by leaks in pipelines, caverns, etc. In addition to combustion, N₂O is produced from other sources including landfills and feedlots. Some of the carbon dioxide equivalents (CO₂e) sources that manufacturers now must measure include fuel oil, fuel gas, natural gas flow and BTU, refinery fuel gas, landfill gas, and black liquor. Other sources that may be measured include refrigerant gases such as chlorofluorocarbons (CFCs) and perfluorocarbons (PFCs), which have extremely high GHG values.

The CO₂e concept is described in the FAQs:

GHGs each have their own heat‐trapping ability. GHG's other than CO₂ have a multiplier associated with them that accounts for their greater ability to trap heat. (This multiplier is called "Global Warming Potential" or GWP). For example, CH₄ has a multiplier of 21, meaning 1 metric ton of CH₄ is the same as 21 metric tons expressed in CO₂e. Customers will convert emissions of each GHG to CO₂e and add them together to see if they exceed the reporting threshold.

The 40 CFR Part 98 regulations impact approximately 10,000 U.S. facilities. On its impact:

Every Emerson end‐user customer in the U.S. will have to follow the "applicability" instructions [EPA applicability calculator] within the new rules to determine if they have to report. It seems the vast majority of large end‐users will have to create and implement a reporting system. ALL Refineries and Petrochemical manufacturers are subject to the new rules, regardless of their capacity. The same is true of any plant making: Adipic Acid, Aluminum, Ammonia, Cement, Lime, Nitric Acid, Phosphoric Acid, Silicon Carbide, Soda Ash, Titanium Dioxide, and several other chemicals. Most other plants have several "stationary combustion units" and will have to report if the aggregate emissions of all these units (boilers, furnaces, etc.) exceeds 25,000 metric tons/year CO2e.

Micro Motion Coriolis flow and density meters measure direct mass flow of both liquid (to 0.05% accuracy) and gas (to 0.35%) from a single device. The guidelines currently call for 5% or better but are expected to tighten in the coming years. The vast majority of these measurements are made on fuel lines to boilers and furnaces.

To help satisfy the regulation's "manufacturer recommended best practice", these devices have on-line meter verification. This verification process helps you determine the performance of the sensor and electronics while the meter remains on line. Compared with conventional off-line verification approaches, this can also significantly reduce ongoing maintenance and calibration costs. Records management required for on-line regulatory reporting as well as routine calibration and troubleshooting is streamlined.

Given the significance of these regulations to U.S. process manufacturers, I'll do future posts looking at some of the other technologies that can be applied to help comply with these reporting rules.

MP3 | iTunes

Being lousy at secrets, I thought I'd share some news in an email from ModelingAndControl.com's Greg McMillan. He's just completed a book, Essentials of Modern Measurements and Final Elements for the Process Industry: A Guide to Design, Configuration, Installation, and Maintenance. It's a collaborative effort with several of the Emerson measurement, final element, automation systems, and safety instrumented systems experts.

Here's a few that I featured on this blog with links to their posts including:

• Mike Boudreaux
• Jim Gray
• Mark Nixon
• Sarah Parker
• Bill Zhou

On the ISA book web site, Greg describes it:

Advances in sensor technology and in digital positioner and variable speed drive algorithms, combined with smart features, offer a step change in the performance of modern measurement instruments and final elements. The installed accuracy of many smart instruments has increased by an order of magnitude. There has been a correspondingly dramatic reduction in the drift of transmitters and a similar improvement in the resolution of control valves.

This comprehensive resource aims to increase awareness of the opportunities afforded by modern measurement instruments and final elements, and to show how to get maximum benefit from the revolution in smart technologies. It builds an understanding of the fundamental aspects of measurements, measurement instruments, and final elements for applications in the process industry. The terminology and ideas presented provide a firm foundation for subsequent chapters that focus on what is needed for lowest life-cycle cost and best automation system performance. The last chapter provides a comprehensive exploration of the technology that supports the rapidly expanding opportunities of WirelessHART instrumentation.

The book is written for students or those new to instrumentation and offers guidance and insights for the more experienced folks among us.

Greg notes that the book is done except for the final reviews of copyediting and layout. The ISA book site has it available for order now, but currently lists October 30 as the in-stock date.

If you're unfamiliar with Greg's past works, he has many of them freely available as eBooks.

Update and bump: I wanted to let everyone know that this book is now printed. I know this because I'm holding one in my hands. It's available for order in the ISA Bookstore but not yet stocked in Amazon.com.

Update 2: ControlGlobal.com's Sound Off! blog gives Greg and team's book 4.5 out of 5 stars.

Part of an organization's willingness to bring their talented folks to the surface, is the organizational commitment to this as a strategy for it to be sustainable. Emerson's Aaron Crews eloquently shares his thoughts on this subject in his post, Social Media Marketing and Sustainability.

One place I see great promise in a sustainable community is the new Micro Motion Online Community. Its focus is to be your online resource for Coriolis flow and density measurement. Not a repository of documents like traditional websites, it's a community to connect people with similar interests in these measurement technologies and expertise. I had a chance to get a sneak preview from Emerson's Mike Tongwarin at the Emerson Exchange.

When I received the email last Friday that it had officially launched, I asked Mike and Lee Rumbles if they had more background about the effort that I could share. I thought I'd include their response in its entirety:

There's really one main reason we created the online community - Customers. Our Customer Advisory Board told us several months ago that one of the key developments they would like to see is an online way to connect with peers, share experiences, build their knowledge and grow their network. This group was clear in their desire to have a forum to act as a knowledge base for sharing knowledge, giving them the ability to self-help through their issues. This high-ranking request was right in line with our commitment to online activities and our growing emphasis on connecting with customers, users, prospects and students on the web.

Micro Motion has spent the last couple of years increasing our internet presence and have noticed that our customers are receptive to those efforts. We've had a spike in web visits and an increase in online requests for documentation, quotes, and general questions among others. This trend towards technology can also be seen by our shift to replace paper manuals to CD manuals, which also is in line with our environmental goals, as well as our web focus.

The Micro Motion Online Community offers a Forum as its main focus with other value-added features we continue to develop further including a Knowledge Wiki. We encourage our members to post their questions or customize an answer based on their knowledge and experience.

The social aspect of the community also plays an important role and one that we hope connects our customers not only to us, but also to each other. We hope this community brings users together to share experiences and knowledge and also builds their networks. Some of the social features include the discussion forums, starting private or public groups, chat room, and the ability to make friends.

We are already making changes to the site based on recommendations and suggestions received. The beauty of the online environment, of course, is the flexibility it offers for continuous improvement - something Micro Motion believes strongly in. Of course, the success of the Online Community is users. We currently have 575 members and it's their involvement and activity that will drive success!

I'd say a community with 575 folks already is off to a great start. If your plant has Coriolis flow and density measurement, you might consider visiting and joining this community.

MP3 | iTunes

In an earlier post, I recapped a podcast on ultrasonic flow meters and their use in custody transfer applications. Gerard Hwang and Dave Seiler, at Emerson's Daniel Measurement and Control business shared an interesting energy analysis with me. It was an energy calculation for various flow measurement technologies in a liquid (oil tanker) loading application.

Typically, liquid loading applications such as crude oil custody transfer between parties, involve large volumes and sizable flow rates. It takes energy to pump these liquids from their source to their destination. Any pressure drop caused by the flow measurement can be directly translated into an energy cost.

In addition to diagnostics around fluid flow phenomena (e.g., cross-flow, asymmetry and swirl) which can increase flow measurement uncertainty, a fundamental design advantage ultrasonic flow meters have in high-volume flow measurement applications is that they are "full-bore" meters. This means that there are no restrictions, internal obstructions, or bends, which will cause a pressure drop across the meter--the loss incurred is that of an equal length of straight run pipe.

The example was from a large U.S. pipeline company, which transports oil, gas, and refined petroleum products. In this case, the liquid was crude oil and its viscosity was 23.3 centipoise (cPs). The flow rate ranged from 1,800 to 22,000 barrels per hour (BPH), and the crude oil had a specific gravity (S.G.) of 0.86. The maximum design pressure was ANSI 300# and a temperature range from -10 degC to 40 degC.

At maximum flowrate, a 16" ultrasonic flow meter resulted in a 0.12 psi pressure drop. Other flow measurement technologies required multiple meters in parallel to accommodate the same volumetric throughput and caused any where from 5-12 psi drop. This multi-meter design also increased the number of block and control valves required around the meters.

The energy cost calculation for loading operations 90 days per year at 22,000 BPH is:

(0.12psi x 22,000BPH / 2,448*) x $0.07 USD/KWh x 24 hours x 90 days = $163

*2,448 is a conversion factor from PSI and BPH to hydraulic horsepower (HP) divided by the pump and motor efficiency to get electrical HP multiplied by the conversion from HP to KW to get power.

In other words, the cost of the energy loss from pressure drop across the ultrasonic flow meter is almost negligible. With the differential pressures across other flow meter technologies, energy costs range from $6,800 to over $15,000 per year.

Now if you multiply this cost by all the flow meters performing these large custody transfer applications in your organization, daily, these energy cost savings add up to reduce operational costs.

Update: I received some feedback on the post and cleaned up a few of the paragraphs above.

Emerson's Trever Ball presented Smart Meter Verification Enhancements Improve Safety and Process Availability at the 2009 Emerson Exchange conference.

Trever began by defining terms. Calibration is performed at the factory. It establishes the relationship between flow and signal produced by the sensor. Validation confirms flow performance by comparing a primary flow standard to the sensor. Verification establishes confidence in performance by analysis of the secondary variables associated with flow. Many times these terms are used interchangeably. Also, frequently calibration or validation is done when only verification is needed.

During factory calibration, baseline measurements are performed in which the smart device can self-check against once operating in the field. For example, Micro Motion Coriolis meters check tube stiffness and Rosemount E-series magnetic flowmeters check against a magnetic field signature to perform ongoing verification.

Smart meter verification is verification on demand, whenever you want on demand or on a schedule. It provides diagnosis of the whole system including the sensor, drive, and signal processing. This verification process provides absolute confidence in measurement performance

For Micro Motion Coriolis Smart Meter verification, the Coriolis meter has no moving parts. Coating and corrosion can impact the stiffness of the meter tubes. Smart Meter verification measures the meter's mechanical characteristics so when a change in the tube stiffness is detected, performance is checked to see if it remains within factory specifications.

Rosemount magnetic flowmeters also have no moving parts and has an expectation that the meter calibration will never change. Over time, the calibration may be impacted if there is a shift in the coils due to vibration, thermal cycling, etc. Smart Meter verification measures the sensor's magnetic field strength characteristics, and when a change is detected, it determines whether the meter's performance remains within factory specifications.

A final example Trever described was the Rosemount 8800 Vortex flowmeter. The vortex sensor is a piezo crystal, which provides a low-level voltage when it is flexed. Vortices in the flow cause the sensor to pulse. The vortex electronics take the frequency of these pulses to deliver a flow output.

Historically, vortex verification has been difficult. It's become easier since properly functioning electronics can be verified by testing with a known frequency. The vortex sensor can be verified by measuring signal strength with a handheld device or via applications, such as AMS Device Manager software.

Trever closed his presentation with some quantified results of Smart Meter verification savings versus traditional maintenance and verification practices. Maintaining these flow devices within factory specification also improves plant availability, product quality, and reduces waste and rework.

MP3 | iTunes

I saw in my Sound Off blog RSS feed that Dan Hackett, part of Emerson's Daniel Measurement and Control business, did a podcast interview with Walt Boyes. The 25-minute podcast is on some new Daniel Ultrasonic flow measurement technology being introduced at the upcoming Emerson Exchange.

Dan starts by describing how these critical ultrasonic flow measurements work. I thought Dan's explanation was more understandable than my Guadalupe River rafting analogy in an earlier post. If there's no flow, the time it takes the ultrasonic pulse to travel across the pipe from one side upstream to the other side downstream and back is the same. As the flow increases, the time difference between the travel across the pipe each way increases--since one way the pulse goes with the flow and the other way it goes against the flow.

Dan described how some of the Daniel liquid and gas ultrasonic flow meters have 4 measurement paths to get different measurements at different points to integrate an average flow. The average axial velocity multiplied by the area of the pipe gives the uncorrected volume flow rate through the ultrasonic flow meter.

He described how these critical meters are used primarily in custody transfer applications. For those not familiar with the term, custody transfer is like the cash register where the possession of feedstocks, intermediates, and finished products changes hands between companies, governments, or countries. The measurements must be highly accurate and agreed to by both parties.

As Walt pointed out in one of his questions, ultrasonic flow measurement, because of low-pressure drop and high turndown capability, can handle a wide range of applications from very high temperatures to very high pressures. Dan described an application in gas measurement where this technology was being applied. Offshore and onshore gas production measure high-pressure natural gas--usually at the custody transfer point with the gas distribution pipelines. High volume consumers of natural gas, such as power plants and aluminum producers will meter the incoming natural gas. Also, many municipal districts measure the incoming natural gas before it goes into their distribution systems for the area businesses and residences.

For liquid custody transfer, crude oil production and processing are typical applications for ultrasonic flow measurement. Dan mentioned that right now it's mainly used in the feedstock and finished products areas of refineries, and less so in the process itself, where other flow measurement technologies are typically applied. In a refinery, the custody transfer surrounding the incoming crude and the refined products such as gasoline, diesel fuel, and kerosene are good applications for ultrasonic flow measurement. A final application Dan notes was liquefied natural gas (LNG) facilities where the incoming natural gas is measured and also in regasifiers where the liquid is converted back to high pressure gas for final distribution.

The new ultrasonic flow meter transducer being shown at the Emerson Exchange extends the temperature and viscosity range to address more applications like the heavy crudes found in the oil sands and oil shales. Typically, conditioning processes were required to reduce viscosity and or temperature, which add operational costs to the custody transfer measurement process.

One of the big enhancements Dan mentioned was on the software side, where diagnostics now embedded expert knowledge to identify conditions such liquid fractions in gas and pipeline deposit layer buildup. In oil & gas applications, the first case helps spot expensive liquid condensate giveaway. Accumulated buildup inside of pipes impacts the integrity of the custody transfer measurements. When these diagnostics are connected to the Daniel CUI 5 or AMS Device Manager software, operators and maintenance personnel are notified of a problem immediately and offered suggestions for corrective action. The CUI 5 baseline viewer provides a consolidated view for monitoring performance within pre-set ranges.

I found the podcast to be 25 minutes well spent as well as the recent email newsletter in getting up to speed on the latest developments in ultrasonic flow measurement and good application fits.

MP3 | iTunes

I've got another great example of an email question I received and answer on which I was cc'ed. It needs to be lifted out of the depths of email inboxes and sent items folders into the spotlight in the hopes it helps others who may have similar questions.

The question:

We are working on a project where the water overflow from a hot lime softener needs to be measured for pH (typically about 9.5) and we also need to take a sample. The sample needs to be cooled to 50 degC which we can do with a heat exchanger. Do you have any information as to the longevity of pH probes if the sample were cooled to 50 degC as opposed to cooling it further to 25 degC?

I checked with Emerson's Dave Joseph, a senior industry manager in the Rosemount Analytical Liquid business. Dave responded:

Your question about pH sensor lifetime is actually quite complicated. pH sensors can fail due to glass breakage, glass coating, glass depletion, reference depletion, reference poisoning, and reference plugging, and that's just to start. Each of these effects are aggravated by temperature to one degree or another, so depending on the expected failure mode, temperature can be more or less of a factor.

Our general rule of thumb is that for every 25 degree C you can expect to half the ideal lifetime of a pH sensor. For instance, if a sensor lasts 2 years at 25 degree C, it might last 1 year at 50 degree C. Note, however, that getting your sensor really cold also tends to decrease lifetime so don't cool the sensor down to freezing expecting a 4 year lifetime.

Although we have sensors that can operate at temperatures exceeding 120 degree C, it is generally good practice to cool samples down to around 50-60 degree C to prolong their lifetime (by a rough factor of 4-6). This is especially true for high pH samples (over 12) that deplete the glass very quickly. In your case, I would not expect that further cooling the sample much below 50 degree C would justify the added piping complexity.

Thanks for letting me pass on your wisdom to others, Dave! Also, for those who may have come upon this post looking for answers to their pH control challenges, make sure to visit the pH category on the ModelingAndControl.com blog.

MP3 | iTunes

As wireless instrumentation based on the WirelessHART standard continues to move into the mainstream, I get great questions about it by email from time to time. Here's one that came in this week that I thought I'd share:

Do you guys know of a wireless alarm system that we could purchase that would accept an input from a level switch and output a wireless signal to a receiver which is 1500ft away to activate a light/horn. The level switch is in a Class 1, div 2 area. We are just looking a for a stand alone system.

One on the common plant situations that leads automation engineers to think about wireless is distance. Many times, infrastructure like cable tray or conduit paths are not in place. Or as in this case, the annunciator (light/horn) is a great distance from where the measurement takes place and where the automation system is located. In most cases like this one with long distances involved, it's not economically feasible to add the cable infrastructure to solve the problem at hand.

I'm not sure about a standalone solution, but know it could be coupled with a small PLC or to an existing automation system. I checked with Emerson's Wireless Manager, Dan Carlson, about how Emerson might address this application. Dan responded:

The end-user could implement a network of 702 discrete transmitters made by Rosemount that take discrete inputs from any type of switch, including level switches. The signals can then be sent to a Smart Wireless Gateway with either Modbus or OPC outputs routed into a PLC-type device [or natively into an automation system like the DeltaV system] to provide signal response.

Once the wireless gateway is in place and communicating with the automation system or PLC, you can add new wireless measurements or final control elements to the wireless network to provide an answer to wide range of applications.

Wireless-Question-How-To-Connect-Level-Switch-To-Light-Or-Horn.mp3 | iTunes

Let's close this week with a new era for us in YouTube-based demonstration videos. The team has just added three new videos produced in high definition (HD) video format. The videos include:

If you click through and see the videos in HD on the YouTube site, what makes the HD quality so nice is that you can go full screen and really see the software screens in clear detail. Until now, videos created over the years and available on the DeltaVsystem YouTube channel did not have the resolution to view some of the software screens well.

In these videos, Emerson's Bill Zhou and Juan Gomez show the interaction of diagnostics available in the Rosemount 3051S integrated pressure, flow, and level multi-variable transmitter and how they make this data available to operators and maintenance personnel to avoid and resolve abnormal situations.

I know that some have written me to say that their IT department blocks these videos. I think the case must be made that there are significant business uses from training videos, to application videos, to even capabilities videos like these.

Perhaps this post is one more URL that you can share to help change the status quo.

In the news a while back was Emerson and Flow-Cal, maker of the leading natural gas accounting software. They introduced Coriolis-specific data integration to the FLOWCAL software. The purpose is:

...to enable direct interface of API Ch. 21.1-compliant Micro Motion Coriolis data with Flow-Cal accounting software for natural gas production and transmission data management.

The API Ch. 21.1 standard refers to the electronic gas measurement portion of Chapter 21, Flow Measurement Using Electronic Metering Systems. It encompasses the flow computer as well as the gauge/impulse lines; cabling/wiring; peripheral devices including counters, pulse generators, on-line analyzers, densitometers and gravitometers; calibration equipment; and measurement software.

I turned to Emerson's Marc Buttler, a manager in the Micro Motion division to get the story for how this integration was made possible. He described the typical natural gas accounting path. It starts with the flow meter measurement on the gas production line. The flow meter feeds a transmitter or flow computer, also known as electronic flow measurement (EFM). A SCADA system typically polls this information, and sends it to the enterprise management accounting software.

The American Petroleum Institute (API) and American Gas Association (AGA) have very strict requirements for this data required by the natural gas accounting software. The data must include the measurement, associated configuration, and the event logs around the measurement.

Marc shared with me that the Remote Automation Solutions business within Emerson has had a longstanding relationship with the Flow-Cal organization. The Micro Motion team also has had a longstanding relationship with their parent company, Coastal Flow. The engineers at Micro Motion and Remote Automation Solutions teamed with the Flow-Cal engineers to complete the path from the Micro Motion flow meters, with a FloBoss 107 or a ROC809 as the flow controller, and ROCLink software used in place of SCADA polling software.

Technically what happens is that the ROCLink software delivers the flow meter data in the Flow-Cal specified .CFX file format for Coriolis natural gas flow measurement required for AGA 11 (Measurement of Natural Gas by Coriolis Meter) and API Ch 21.1 compliance.

By automating this flow of information through this collaborative R&D effort, energy producers can increase the reliability of their natural gas measurements and production accounting, while reducing the maintenance and capital costs. Much of these improvements come from the accuracy and reliability of Coriolis measurement. It measures gas volume without additional temperature or pressure measurements, which reduces the components to purchase and maintain.

As Coriolis measurement continues to move into the mainstream of natural gas flow metering, Marc sees more SCADA polling suppliers developing and providing the connection from the electronic flow measurement device to the Flow-Cal software to provide the end-to-end natural gas production and transmission management.

MP3 | iTunes

Emerson's Bill Zhou is in town this week, escaping the cold north of Minnesota. You may recall Bill, from his Emerson Exchange plugged impulse line video demonstration. Actually, his purpose was not to see the Austin wildflowers in full bloom, but to work with the DeltaV product application specialists to share some of the capabilities in the Rosemount 3051S transmitter and what information it shares with systems like the DeltaV system. The team is also creating a video for us to add into the DeltaV YouTube site and other locations.

I've shared some of the statistical process monitoring (SPM) technology and how it helps spot abnormal situations by being closer to the process than the automation system is. These 3051S devices measure pressure, differential pressure (DP) level, and DP flow. They sample the process variable (PV) at 22 times per second compared with a typical 1-2 times per second from the automation system level.

It's this higher frequency data collection and applied statistical analysis to measure process variability that provides operations personnel more information about what's really happening in the process. Changes in this process variability can help uncover process- and equipment-related problems. Bill recommends using this high-resolution process variability as seen by the transmitters and following the four-step SPM model: Collect, Analyze, Decide, and Act.

The Collect step is about gathering as much process information as possible by trending the pressure and process variability inside the data historian application. With this collected information, step 2 is to Analyze the information and initially to establish a baseline. In subsequent times, process variability reductions, calculated by SPM can indicate process conditions like plugged impulse lines.

Step 3, the Decide step, determines the appropriate threshold limits to warn operators or maintenance personnel when actions need to be taken. The AMS Device Manager is used to set alerts based upon a change in process variability. Bill set a threshold of 30% process variability change in his demo example.

Step 4, the Act step, creates a notification for action once the threshold is crossed in the form of an alert on the DeltaV operator or maintenance station. Typically, specific operating procedures would be created for the critical measurement alerts. The actions might include checking the impulse line or other process/equipment condition based upon what the transmitter is measuring. These alerts are included with the historian process history to help achieve a wider view of what's happening in the process and identify future abnormal situations.

I'll update the post and embed the video once it has been produced and uploaded to YouTube.

MP3 | iTunes

I always like receiving goodies that I can pass along to the readers of this blog. This one, a boiler blowdown savings calculator, is from Emerson's Jim Thompson. Jim is a manager in the Rosemount Analytical Liquid business.

Jim probably knew that I'm definitely not a boiler blowdown expert, so he was kind enough to point me to a great Boiler Blowdown Fact Sheet developed by the North Carolina Division of Pollution Prevention and Environmental Assistance.

For those like me who may have heard the term but not have known what it really meant, the fact sheet sums it up:

To avoid boiler problems, water must be periodically discharged or "blown down" from the boiler to control the concentrations of suspended and total dissolved solids in the boiler. Surface water blowdown is often done continuously to reduce the level of dissolved solids, and bottom blowdown is performed periodically to remove sludge from the bottom of the boiler.

It makes good economic sense to perform these blowdowns. You can reduce fuel consumption, use less chemical treatments, and reduce heat loss in the steam you are producing. Automated boiler blowdown operations can:

...save about 2 percent of a facility's total energy use with an average simple payback of less than one year.

Jim pointed out that measurement of boiler feedwater conductivity is an indicator of the concentration of dissolved solids. Rosemount Analytical conductivity sensors, transmitters, and analyzers are used to measure for these dissolved solids. A blowdown system typically includes an automation system running the PID loop, a sample cooler and downstream conductivity sensor & transmitter as the loop input, and the blowdown control valve position as the loop output. Depending on the boiler application, conductivity, pH, dissolved oxygen and free chlorine may also be measured and controlled on the feedwater and makeup water lines.

The calculator uses the maximum recommended concentration limits according to the American Boiler Manufacturers Association (ABMA). Also, the American Society of Mechanical Engineers (ASME) has developed a best operating practices manual for boiler blowdown. The recommended practices are described in Sections VI and VII of the ASME Boiler and Pressure Vessel Code. The calculator helps you identify energy-saving opportunities by comparing your blowdown and makeup water treatment practices with the ASME practices.

If your process includes boilers, give the calculator a try to see if you have opportunities to improve efficiency and reduce ongoing maintenance costs.

MP3 | iTunes

Here's a story about a portable high-flow petroleum pipeline-proving rig. If you're in the oil & gas production, refining, or distribution business, I probably don't need to define what this is.

For the rest of us, a prover:

...is used for rapid, accurate calibration of a wide range of flow measurement technologies. Applications range from load rack, crude and refined product pipelines and marine terminals to offshore. The Compact Prover is used for rapid, accurate calibration of a wide range of flow measurement technologies. Applications range from load rack, crude and refined product pipelines and marine terminals to offshore platforms and FPSOs.

It's important to prove the accuracy of the flow meters measuring the hydrocarbons to account properly for the revenue it produces. As I've mentioned in an earlier post, this has implications for Sarbanes-Oxley financial compliance in the U.S.

Emerson's Dave Seiler, part of the Daniel measurement and control group, shared a story of a recently completed project. The team provided a Daniel compact prover to C&W Meter, a company that provides proving services to truck loading, pipeline, and custody transfer meters for major oil companies all through the North Eastern US.

Dave described the project as a portable 42-foot long custom trailer on which C&W Meter mounted a large 40 kW generator on the top shelf and at the back mounted some 12" hydraulically operated loading arms that allows them to connect to large, high-flow pipelines. C&W meter uses this 34" Daniel portable prover for large size meters on a pipeline. They believe this application to be the largest portable prover in North America.

The C&W meter website describes this prover application:

Currently in operation is our portable High Flow petroleum pipe line proving rig complete with Daniel 34" Small Volume Prover and 12" Master Turbine Meter. The trailer mounted proving system has a maximum flow rate of 18,000 Bph/12,600 Gpm of refined petroleum products - gasoline and distillates. The Master Turbine Meter is used for proving Ultrasonic Flow Meters that require a long sample time to achieve the required data uncertainty. The High Flow proving rig has 12" loading arms with a pressure rating of ANSI class 300# - 720 psig max working pressure. The loading arms are hydraulically actuated for fast, easy connection to the pipe line. The proving rig is fully powered by an onboard diesel generator.

Now I realize all this might be tough to visualize if you're not already familiar with provers, so C&W Meter's Mike Scott was kind enough to send me some pictures of the prover in action. I want to first warn those of you with social media-blocking IT departments, that I've uploaded the pictures to Flickr in order to embed this slideshow.

Hopefully, as more process automation bloggers and trade magazines use sites such as Flickr, YouTube, Twitter, etc. these IT walls will come down!

MP3 | iTunes

Emerson's Steve Jones, part of the Micro Motion Coriolis flow and density measurement business, recently wrote an article on bunker metering for Bunkerspot magazine. Entitled, Critical Mass in the Bunker Industry, it describes the importance of accurate measurement of bunker fuel--also known as heavy fuel oil (HFO).

For those not familiar with bunker fuel, I found this definition:

Bunker fuel is also known by other names: heavy oil, #6 oil, resid, Bunker C, blended fuel oil, furnace oil and other often locally used names. No matter the origin of bunker fuel it has common properties where ever found: color, viscosity, contaminants, and operator problems.

In the article, Steve pointed to the challenges associated with trying to measure volumetrically the flow of bunker fuel used in the marine industry. Measurement errors are typically 1-3% and can be as high as 5%, which can lead to large discrepancies between fuel supplier and fuel consumer. Imagine if your car's gas gauge and the gas station refueling pumps were accurate to plus or minus 3%. You'd be wondering if you'd be getting all the fuel you purchased and wondering if you had fuel left in your tank as it runs low.

A better approach is to use mass-based measurement with Coriolis flow meters. Mass measurement can accurately measure the different bunker fuel grades, and impurities that have not been filtered out. Steve also noted:

Coriolis meters are non-intrusive, meaning that there are no moving parts or obstructions in contact with the fluid being measured. In addition to mass measurement, a single device provides an independent and very accurate density measurement of the fluid and a temperature measurement - three measurements from one device.

Bunker delivery operations have tank-stripping processes, which clear the tanks of sludge and water. This process means air can become entrained with the bunker fuel. Coriolis measurement provides accurate measurement even in these conditions, as I've discussed in an earlier entrained gas post.

Steve raised one other important requirement for bunker applications--in-situ meter verifications. He wrote:

Meter verification technology on Micro Motion meters measures the actual mechanical characteristics to a very high accuracy -- in line and without removing the meter. When a change in the meter's tube performance is detected, the results determine whether measurement performance remains within the original factory specifications.

Steve described bunker measurement mass flow meter trials with A.P.Moller-Maersk and ExxonMobil Marine Fuels. These trials are entering their second phase with a view to gain custody transfer certification. Steve concludes:

While Emerson continues to work with A.P.Moller-Maersk, ExxonMobil and others to provide international metrology certification of Coriolis measurement in fuel oil bunkering applications, initial test results illustrate the great potential this technology offers to the advantage of the marine industry as a whole.

MP3 | iTunes

A common theme found in my 2008-blog posts was energy efficiency. Given the state of the global economy, 2009 posts will likely have a common theme on ways to improve profitability through cost savings and productivity increases.

Just before the holidays, my email spy service found a new flow measurement paper written by Emerson's Bert Konings. The paper, Accurate Flow Measurement Improves Profit, describes flow measurement and its direct impact on the profitability of process manufacturing plants. He sums up the importance of flow measurement:

Get it right, and the plant is more efficient, produces less waste, minimizes rework and lowers maintenance costs. Get it wrong and the consequences can be significant. Inaccurate measurement in fiscal applications can lead to a plant being overcharged for raw materials or effectively giving away the product. Inaccurate meters used to measure utilities can also add to costs. Meters used to provide a mass balance across the plant need to be accurate or technicians will either spend time chasing product losses that aren't there, or they will set the tolerance so wide that product losses are not identified early enough.

As I've discussed in earlier flow measurement posts, the technology choices are plentiful. Bert describes the pros and cons of many types including differential pressure across an orifice plate or venturi, positive displacement (turbine meters, oval gear meters), ultrasonic, vortex, and Coriolis mass flow.

Bert describes Coriolis measurement as being:

...based on the principle that when fluid is moving through an oscillating tube, forces are induced which causes the tube to twist. The amount of twist is directly proportional to the mass flow rate of the fluid flowing through the tube.

What has made the Coriolis measurement technology popular is its high accuracy and lack of moving parts. High accuracy helps the quality, throughput/productivity side of a plant's economics. Maintenance costs are helped by the lack of moving parts. As Bert notes:

By selecting the right materials for an application, the effects of erosion and wear can be avoided and maintenance reduced to virtually zero.

Other advantages include direct mass measurement, online density measurements, high repeatability, and low pressure-drop across the meter.

A drawback to retrofitting other flow measurement technologies with Coriolis measurement has been the need for four wires (or up to 9 based on automation supplier.) Running additional wires and conduit is often an expensive proposition, $20 USD / foot according to one U.S. Chemical manufacturer. The Micro Motion team addressed this in 2008 by releasing a 2-wire Coriolis flow and density measurement meter. I discussed some of the applications for chemical manufacturers in an earlier post. Other industries and applications Burt lists are:

...suited for use in the chemical, petrochemical and refining industries, and for continuous process and mass balance applications.

Give the article a read if you're weighing flow measurement options.

MP3 | iTunes

I had a chance to meet Emerson's Philip Schwarz a few years back in a multi-divisional marketing meeting. He had a slot on the agenda to discuss the trends in the oil & gas industry. He leads these efforts for Emerson Process Management's Rosemount measurement products. He was one, dynamic presenter, if you ever have a chance to hear one of his talks. Maybe I'll capture some video and post it in YouTube the next time I catch him presenting.

I saw an email from Philip where he mentioned that the oil & gas producers have been big adopters of wireless field device communications technologies. Philip noted around 9 in 10 of these oil and gas wireless applications were in onshore oil & gas fields. A big driver of this technology adoption has been for gross oil production flow monitoring applications.

The traditional way to measure gross oil production has been to use portable meter skids. These skids measure the oil, gas, and water content for each producing well on a site--when hooked up one by one. Since many fields are geographically dispersed, these measurements may be done one per month up to twice per year. After a well is tested, its production rate is assumed to be the last-tested measurement. It's important to note that these measurements are not to control the wellhead, but to monitor the production rates for each well.

Now, if five months have passed, this last-tested measurement might not be very accurate. And problems may have occurred in the subsurface well formation causing a production drop.

The main reason these wells have not been fully instrumented and been communicating continuously is the labor and installation costs of measurement devices, cabling, remote terminal units (RTUs), batteries, radios, etc. In many areas, these wells typically don't have the high production rates of offshore production wells. Hence, the traditional solution of a portable skid and schedule to conduct the flow measurements has been employed.

Wireless measurement devices and self-organizing WirelessHART networks have changed the economics by significantly reducing the infrastructure costs. To do the gross oil production measurements, these onshore sites install Rosemount 3051S wireless pressure transmitters and 648 wireless temperature transmitters. Instead of once per month or twice per year, each well can be measured on the order of seconds.

Communications between wireless devices can extend up to half a mile as the transmitters from surrounding wellheads self-organize to form a network with the wireless gateway devices. None of the cabling, cable trays, etc. is required, which significantly reduces the installation cost barrier.

Philip shared a 2005 Society of Petroleum Engineers (SPE) paper with me written by engineers with one of the major U.S. oil producers. It shared a vision of the digital oil field that provides real-time monitoring, analysis, and control for optimum field management. This vision included making the oil field more like a factory where there is a higher level of measurement and control to improve efficiency.

Technologies like WirelessHART self-organizing network communications and wireless-enabled field devices here in 2008 make possible many of the visions that were not economically justifiable when this paper was written.

Next time, a nice video of Philip talking about this will save around 550 words!

MP3 | iTunes

Emerson's Dale Perry alerted me to a great article on safety-certified sensors in the November 2008 issue of Control Engineering magazine. Dale manages the Rosemount pressure measurement line of products.

The article, Practice Safe Sensing; Safety-certified sensors promise to cut costs and boost performance. But the tradeoffs must be carefully considered., described the advances in both numbers and intelligence of sensor devices used in process safety applications. The article defined these devices as:

...sensors can be certified by third parties to meet safety integrity levels [note: I've added hyperlinks for additional reference], or SIL, designations found in IEC 61508. One positive result of this is the potential to use fewer sensors without compromising safety, leading to a decrease in wiring and installation costs. Another positive effect is the potential for improved process control, largely due to increasingly intelligent sensors.

Exida's principal partner, Bill Goble, shared how the number of safety certified transmitters from automation suppliers has increased from five in 2003 to 24 in 2007--with more in testing and certification as automation suppliers improve the design and testing processes required to achieve certification to the safety integrity levels.

To mitigate risk for higher SIL applications, often you need multiple sensors (if not safety-certified sensors) connected in a one-out-of-two (1oo2) or two-out-of-three (2oo3) voting arrangement. Dale is quoted in the article and he discussed and amplified on the fewer sensors tradeoff:

Fewer sensors increase the possibility of a false alarm, which carries a cost since it might shut down a process needlessly.

The economic tradeoff is capital cost savings of fewer sensors and the associated installation and maintenance costs versus the probability of lost production from unplanned shutdowns caused by spurious trips.

Dale described how incorporating the features necessary for certification became part of research & development best practices. The R&D team incorporates these best practices as new devices are developed and existing ones are enhanced. These safety-certified sensors still carry extra expenses like order checks of options for the required SIL application, failure modes, effects, and diagnostics analysis (FMEDA) documentation, serial numbers and failure data shipped with each sensor.

On the increasing level of intelligence, Dale noted:

The same intelligence that makes sensors safer increasingly supplies other capabilities... Users demand predictive diagnostics beyond the sensor. They want this functionality because more insight into a process helps prevent abnormal, and potentially unprofitable or dangerous, situations.

Dale also gave a peek at future of Rosemount safety certified sensors when he stated:

We see these advanced process diagnostics, as well as loop diagnostics, being included in future safety certified products.

When developing and executing your IEC 61511 safety lifecycle programs, the intelligence in these sensors and throughout your safety instrumented functions (SIF) can help improve the diagnostic coverage and reduce manual testing.

MP3 | iTunes

Last week I mentioned uploading two of ModelingAndControl.com blog's Greg McMillan's recent presentations. Like I did with his first presentation, here's a short recap of the second one, Control Loop Foundation for Batch and Continuous Control:

What are great about Greg's presentations are the specific application examples. Visit the slides 19-21 to see ways of improving neutralizer control using Feed forward control, signal characterization and proper piping to provide proper spacing for measurement devices. Similarly, slides 22-24 show ways to improve distillation column control using Feed forward control and signal characterization. You mostly don't realize the benefits of improved control until you reduce variability and move the setpoint closer to the operating limit.

Greg is really good at boiling things down. Here are his words summing up basic opportunities in process control (from slides 27 and 28):

• Decrease stick-slip and improve the sensitivity of the final element (Standard Deviation is the product of stick-slip, valve gain, and process gain)
  • Use properly tuned smart positioners, short shafts with tight connections, and low friction packing and seating surfaces to decrease valve slip-stick and dead band (do not use isolation valves for throttling valves)
  • If high friction packing must be used, aggressively tune the smart positioner
  • Improve valve type and sizing and add signal characterization to increase valve sensitivity
  • Use variable speed drives where appropriate for the best sensitivity
• Improve the short and long term reproducibility and reduce the interference and noise in the measurement (Standard Deviation is proportional to reproducibility and noise)
  • Use magnetic and Coriolis mass flow meters to eliminate sensing lines, improve rangeability, and reduce effect of Reynolds Number and piping
  • Use smart transmitters to reduce process and ambient effects
  • Use RTDs and digital transmitters to decrease temperature noise and drift
• Reduce loop dead time (Minimum Integrated Error is proportional to the dead time squared)
  • Decrease valve dead time (stick and dead band)
  • Decrease transport (plug flow volume) and mixing delay (turnover time)
  • Decrease measurement lags (sensor lag, dampening, and filter time)
  • Decrease discrete device delays (scan or update time)
  • Decrease analyzer sample transport and cycle time
• Tune the controllers (Integrated Error is inversely proportional to the controller gain and directly proportional to the controller integral time)
• Add cascade control (Standard Deviation is proportional to the ratio of the period of the secondary to the process time constant of the primary loop)
• Add feed forward control (Standard Deviation is proportional to the root mean square of the measurement, feed forward gain, and timing errors)
• Eliminate or slow down disturbances (track down source and speed)
• Add inline analyzers (probes) and at-line analyzers with automated sampling since ultimately what you want to control is a composition
• Optimize set points (based on process knowledge and variability)
• To realize the benefit of reduced variability, often need to change a set point

He sums up the presentation with these key points:

• Tune the loops
• Use digital positioners and throttle valves to get resolution better than 0.5%
• Use Coriolis and Magmeters to get accuracy better than 0.5% of rate
• Add cascade and feed forward control for disturbances
• Model the process to dispel myths and build on process knowledge
• Improve the set points
• Add composition control
• Reduce the size and speed of disturbances
• Transfer variability from most important process outputs
• Add online data analytics (multivariate statistical process control)
• Add online metrics to spur competition, and to adjust, verify, and justify controls

View or download the presentation if you think some of this guidance might benefit you.

MP3 | iTunes

Earlier this week, I listened to Gary Mintchell's personal podcast, Automation Minutes Episode 59 (iTunes | RSS feed). Gary interviews Emerson's Jonas Berge, a member of the ISA104, Electronic Device Description Language (EDDL) standards committee. EDDL is also recognized globally by international standard IEC 61804-3. A few weeks earlier, Gary had interviewed a member of the FDT (a competing standard) marketing committee.

Jonas provides a detailed summary of what EDDL means to process manufacturers. It's a standard to display information in intelligent field devices communicating via HART, WirelessHART, Foundation fieldbus and Profibus back to the device management software and automation system. EDDL files are standards-based compressed text files that reside in the device management software to provide a consistent view to devices from different manufacturers for setup, calibration, diagnostics, etc. Through the EDDL file, the device manufacturer tells the system what command to send to get information from the device, how to decode it, and how this manufacturer would like to present the data.

Jonas offers a great analogy of how EDDL is like HTML. Both are text-based files. Client software (device management software and web browser) renders both, both are platform independent since they are text files and not installed programs, and both are version independent again since they are not installable programs. And similar to how devices like PCs, MACs and smart phones render HTML pages, PCs and handheld devices with device management software render smart device information.

Also, in how HTML supports sophisticated displays, EDDL supports sophisticated ways to render valve signatures, vibration spectrums, radar level "echo curves", dial gauges, historical trends, and step-by-step "wizard" procedures. Jonas points out that these graphical enhancements were added to the EDDL standard in 2006 to address the NAMUR NE 105 requirement to support access to full functionality in complex devices in the way the device manufacturers want this functionality to be displayed. These complex devices include valve positioners, variable speed drives, machinery health transmitters, wireless gateways, and bus diagnostic modules to name a few.

The design basis behind the EDDL standard is that the device manufacturer knows best what information their devices contain and how it should be displayed. The device manufacturers can make the full functionality of their devices visible and available on any system. The device management software suppliers know best how to provide a consistent view of trends, gauges, step-by-step procedures, etc.

For plant staff members who manage the device management software, the EDDL files do not become obsolete as the operating system is revised or security patches are added. Since these are text-based files, multiple versions can exist together within the device management software to address the plant realities of different devices, from different vendors, communicating with different digital protocols.

The information presented from these various devices have a common look and feel for the instrument technician and others who access the information. And the integrated diagnostics provided by the EDDL standard meet the NAMUR NE 91 requirements.

I captured a quick video at the recent ISA Expo 2008 in Houston, Texas. I just received some photos and ISA104 / EDDL Booth Report that show systems from ABB, Emerson, Invensys, and Siemens interoperating with advanced valve positioners and transmitters from Emerson, Endress+Hauser, Invensys, Masoneilan, MTL, Metso, Samson, and Siemens. These pictures demonstrate this interoperability in action:

MP3 | iTunes

You might recall Emerson's Bill Zhou from a quick, Rosemount transmitter demo video done at the Emerson Exchange a few weeks ago.

I asked Bill if I could get a copy of his and Andrew Klosinski's recent National Petrochemical & Refiners Association (NPRA) presentation, Advanced Diagnostics: 4 Steps to Better Decision Making.

The focus is on how advanced statistical process monitoring (SPM) technologies in intelligent field devices can help process manufacturers reduce maintenance costs, improve product quality and increase process uptime. All of that is easy to say, but the good thing is this presentation offers many case studies showing how.

First, from a technology standpoint, it's important to understand that a transmitter is much closer to where the action is, than the automation system. It touches the process as it measures temperature, level, flow, pressure, etc. Transmitters like the Rosemount 3051S, measure the process at 22 times per second instead of 1-2 times per second that is typical at the automation system level of the hierarchy. This higher resolution sampling is the basis for the statistical process monitoring to detect abnormal situations.

This statistical trending of process information is step one of the four steps to better decision making. It's followed by event correlation, then the creation of specific alerts to warn operators and/or maintenance folks, followed by actionable information to correct the situation before the unplanned shutdown, quality excursion, or asset failure occurs.

One example is a plugged impulse line. From a traditional view, an operator might see a quick drop in flow, with the valve position rapidly opening to try to compensate. It might take the operator quite a while to figure out why this occurred. During this troubleshooting period, process oscillations and shutdowns might occur. This same scenario seen from the transmitter's statistical perspective would show a sharp drop in the standard deviation. This indicates a plugged impulse line condition. In the real case study shared, Bill and Andrew show the dirt that had accumulated inside the pipe wall. Some dirt tore off the wall, which caused the plugging of the impulse line. Since the transmitter shared this insight, the problem was addressed far more quickly than with traditional troubleshooting methods.

Additional SPM-based advanced diagnosis and communication examples included furnace flame instability, DP level agitation loss, pump / valve cavitation, turbine blade wear, pressure transient detection, and distillation column flooding.

The common thread is the high-resolution, statistical monitoring of a process variable (PV) signal to identify and communicate the abnormal situation. In the case of burner flameout, flame instability shows a sharp increase in standard deviation of measured fuel gas pressure.

In the case of distillation column flooding, efficient separation stops, diagnosis is difficult, and repair is time consuming. Looking at differential pressure (DP) measurement across the packing from an SPM perspective shows an increase in standard deviation that correlates as a leading indicator of incipient flooding.

Make sure to view the presentation, if you have any of the other cases not highlighted in this post. Also, I'll keep working to try to get Bill to share some of these examples in video form, now that he's a YouTube star!

MP3 | iTunes

Update: I added a better link to the advanced diagnostics section of the 3051S and fixed the link to the NPRA.

Last week at the ISA Expo in Houston, I sat in on a great session featuring Emerson's Ed Bailey, as well as folks from Siemens, Ametek and a private consultant with years of experience with Dow Corning. The session was entitled, Energy Management Issues for Process Optimization, and it had the following description:

Subjects open for discussion in this session include nearly anything relevant to this topic, not just process control and instrumentation. Expect discussions regarding process maintenance, process modifications, maybe whole new processes that were less cost effective under the old energy cost structure but now are more cost effective.

Ed leads the technology development efforts for the Rosemount Analytical Gas measurement products. He kicked off the panel discussion showing the forecasted growth of energy production. From an ExxonMobil outlook study, most of the world's growing energy needs will continue to be met by the combustion of oil, gas, and coal.

To help manage the carbon emissions, to deal with the increases in fuel costs over their historical averages, and to operate in an environment with increasing governmental regulations, process manufacturers have an ever-increasing need for improved combustion flue gas analysis. The best way to minimize carbon dioxide (CO₂) emissions is to operate existing combustion processes at their maximum efficiency.

Ed described some of the existing industry practices like averaging the output of a few analyzers as not providing enough insight to diagnose and optimize the burners. Burner differences and stratification are normal conditions that this averaging strategy does not well address. Instead, Ed recommended a mix of oxygen (O₂) and carbon monoxide (CO) measurements be used combined with neural network strategies that enable more complex models to be created to maximize efficiency versus the load/fuel variations--and to minimize mono-nitrogen oxide compounds (NO_x). The key point is that more discrete measurement points, which in turn feed more sophisticated control algorithms, will drive efficiency.

One of the discussion points during the session was the use of zirconium oxide (ZrO₂) oxygen analyzers to measure the residual oxygen remaining in the flue gases from any combustion process. Ed mentioned the Rosemount Analytical in-situ oxygen transmitter as an example of a zirconium oxide oxygen analyzer to help provide data to better control and optimize the combustion process.

An interesting question came into the panel about the safety considerations of running the combustion process right on the edge at its most efficient but potentially dangerous point. The panel had good thoughts that you need to separate the control aspects from the safety instrumented system burner management aspects. Like any process with safety risks, a risk analysis and risk mitigation strategy per the IEC 61511 international safety standard is critical.

MP3 | iTunes | My Podcast Alley feed! {pca-d211b332524855a78944048f9c70f6e7}

As reported by the Automation Gear blog, a big breakthrough has come to Micro Motion Coriolis flow meters. They can now be powered with two wires. These same wires carry the process variable and digitally communicate other process variables back to the process automation system via HART.

I did some reading and learned that that ultra-low power technology in the transmitter coupled with an optimized Coriolis sensor design made it possible to power these flow and density meters on a 4-20mA HART signal. Process manufacturers should continue use the 4-wire design for the real demanding applications like fiscal metering and custody transfer, meter verification and ones with entrained air.

Outside of these demanding applications, many mass flow, volume flow, density and temperature applications are well suited for the 2-wire Coriolis meter.

I caught up with Tom O'Banion, who leads the chemical industry efforts in Emerson's Micro Motion division. He noted that Coriolis technology has increasingly been used to measure liquids and gases because of its accuracy and reliability compared with other flow measurement technologies.

With units typically spread over great distances, installation costs have been one limiting factor in the use of Coriolis technology. Tom noted one refiner's estimate of $15 per foot plus labor for the cost of pulling the additional power wires needed for the 4-wire transmitter. This can add up quickly in tank farm or hydrogen metering applications that are typically long distances from the rack room.

Many natural gas metering stations on individual units were installed when natural gas was inexpensive--$1/Mscf. With prices now closer to $8/Mscf, chemical manufacturers and refiners want to track natural gas usage much more closely to optimize their operating costs. A typical small ethylene cracker may consume $200-$300 million in natural gas per year. Instead of differential pressure across orifice plates or turbine meters, a two-wire Coriolis meter can more accurately measure natural gas consumption and provide the flow, density and temperature measurements via HART back to the automation system for tighter control.

Another application Tom mentioned is hydrogen metering. It is usually located along the perimeter of the refinery. It's very expensive and quite difficult to measure with conventional technologies. Using the existing wiring, the 2-wire Coriolis meter provides more accuracy and less maintenance.

Tom also noted that installation costs with the additional wires sometimes prevented the use of Coriolis technology in applications for which it was better suited--especially if the analysis had been based on installed costs rather than lifecycle costs (which favors Coriolis technology with no moving parts.) The two-wire version shrinks the installed cost difference.

It's great that technology continues to advance to create more opportunities to optimize and save energy. I'll continue to pass along applications as I come across them.

On several occasions, I've discussed the subject of flow measurement and custody transfer. My WatchThatPage email spy service alerted me to a great new article by Emerson's N.K. Chaudhary. He's a member of the flow group based in Singapore.

His article, Improving Custody Transfer, describes the role of Coriolis direct mass flow measurement and some tips when using them in a custody transfer application. In describing the importance of good measurement in custody transfer, I'll borrow N.K.'s words:

Whenever liquid product such as refined petroleum changes custody from one supplier or distributor to the next, it must be accurately measured and scrupulously accounted for.

There are many types of flow technologies. The article describes the three basic categories including inferential volumetric flow, direct volumetric flow and direct mass flow. Each has advantages and disadvantages. Inferential flow measurement devices include magnetic, ultrasonic, differential pressure and turbine-based flow meters. Positive displacement (PD) technology fits in the direct volumetric flow category.

The bulk of the article describes direct mass flow measurement. The best examples of these are Micro Motion Coriolis flowmeters. N.K. describes how these meters arrive at a volumetric flow rate:

To determine a volumetric flow rate, a mass flow meter must also know the density of the fluid, which is accomplished by measuring the natural frequency of tube vibration. The fluid's flowing density is proportional to the square of the period of vibration of the flow tubes (inversely proportional to the frequency squared).

Coriolis flowmeters were approved by the American Petroleum Institute (API) in custody transfer applications in 2002 (API MPMS 5.6). N.K. cites a number of reasons that Coriolis technology has been widely accepted in custody transfer flow measurement:

...longstanding high accuracy and repeatability, versatility, reliability, tolerance of solid particles, and more recently low pressure drop and high performance.

N.K. offers some installation guidelines such as to avoid installing the Coriolis sensor at the highest point in the pipe. This is where gas is most likely to separate out. As I mentioned in an earlier entrained gas post, digital signal processing can filter out signal disturbance caused by slug flow conditions.

Unlike many of the other flow measurement technologies, Coriolis meters can be installed without long, straight pipe runs upstream and downstream which can simplify the installation. In applications with very high flow rates, it may make sense to install multiple Coriolis flowmeters in parallel. The total flow measured is the sum each output.

The article also describes OIML approval standards and proving methods to meet regulatory requirements. If you are considering alternatives for flow measurement in custody transfer applications, this article might help in your analysis.

Recently, one of my RSS feeds alerted me to a new Micro Motion 2400S transmitter packaged in stainless steel for the ELITE Coriolis flow and density meter line. This 316L stainless steel packaging is:

Rated to IP66 and IP67, the corrosion resistant stainless steel housing is ideal for applications where instruments are subjected to regular caustic wash-downs, which are typically found in the food, beverage and life science industries. The 316L construction is also ideally suited for marine and offshore environments.

I caught up with Emerson's John Martin, a Food & Beverage industry manager for the Micro Motion family of products. I wanted to get the story behind the design of this product.

For those that have never been inside a food & beverage or pharmaceutical manufacturing process, John shared how you'll be struck by the bright, shiny silver look you see around the process. Hygienic standards are paramount in these industries and a mild caustic (e.g. sodium hydroxide) is often used to wash down the processing equipment. Standard painted-aluminum transmitter housings do not do well in this caustic environment. This new 316L stainless steel housing allows the transmitter to be integrally mounted with the Coriolis meter and provides a local display at the measurement point for the operations personnel.

John noted that normally, transmitters with aluminum and painted-aluminum housings had to be mounted remotely, in stainless steel enclosures or control rooms, to avoid the corrosive environment. This installation method meant more engineering and installation costs.

This 2400S transmitter supports DeviceNet and Profibus DP communications. These are common digital bus communication protocols used by PLCs and other automation systems like Emerson's DeltaV system. Across two wires, these transmitters communicate process and diagnostic information back to the controllers. From the press release:

The result is that one instrument can provide flow, density and temperature measurements, eliminating the need for multiple sensors and the wiring/configuration costs associated with them. In addition, digital communications unlock instrument diagnostic information, such as drive gain, meter verification and other alarms.

John also shared with me that other industries like offshore oil and gas and other marine environments have corrosive environments caused by saltwater and salt in the air, making them good candidates for this stainless steel transmitter housing.

I do know from my days back as an engineer working on offshore Gulf of Mexico oil and gas platforms, that we put the instruments with painted aluminum housing inside 316 stainless steel junction boxes to protect them from the corrosive, salt-air environment. This packaging option might have reduced the size/number of junction boxes required.

Update: I just saw a Twitter "tweet" from @timalosi who reminds me:

there is more to hygenic than stainless. draining is much more important. the Housing is just for looks

Tim, point taken and all in 140 characters or less!

My colleague, Deb Franke, pointed me to a great article in her RSS feeds. The ChemicalProcessing.com article, Innovative Fixes for Saving Energy in Plants, describes some ideas to help reduce plant energy costs. Although energy costs have come down in recent weeks, they are still one of the largest controllable costs as I have mentioned in an earlier post.

The article points out innovative solutions including dual drive pumps, variable speed motors, water/glycol systems, automated blowdown systems, low BTU sweep gas and wireless sonic leak detectors. Give the article a read if you think some of these might apply in your plant processes.

I forwarded the article to Emerson's Lou Heavner, whom you may recall from earlier advanced process control application posts. I asked what new and innovative, energy saving ideas he might have to share.

Lou had a couple of ideas. But, being the modest sort, he added a caveat that they may not qualify as new or innovative. To me, if you're looking for ways to reduce your energy costs and you didn't consider one of these, it's definitely new.

Lou's first thought was on distillation processes. He writes:

In distillation, relative volatility and hence difficulty of separation tends to improve at lower pressure. When cooling water and/or air are used to condense the overheads, the pressure is often tightly controlled for stability in the face of changing ambient conditions and the extra cooling capacity available during nights or colder weather is not fully utilized. If pressure is allowed to "float" and as much condensing occurs as is possible, pressure will fall in the column and separation will normally improve. This means less heat is needed in the reboiler and hence energy savings when using steam or some other "costly" utility stream to provide reboil.

His second thought was around combustion processes burning fuel gases with changing compositions. Lou notes:

In heaters or boilers where the gaseous fuel consists of a hydrocarbon mixture of varying composition (like refinery fuel gas), a change in fuel can have an effect on the heat generated by combustion and on the excess air level in the flue gas for a given fuel flow rate. Sometimes, if variability of the flue gas justifies, companies will install fuel quality analyzers that measure composition or heating value. In many cases, the same thing can be achieved and better flow control at the same time, by using a Coriolis mass flow meter. It turns out that the mass flow of a hydrocarbon and the "btu" flow are directly related since both are related directly to MW.

You can't do this with PT compensated flow, because it knows nothing of MW. But Coriolis measures mass directly and can be used to reduce variability of "btu" feed to the burner. This can be dramatic where the fuel gas varies significantly. It is not a good solution if the "btu" content changes due to the presence of inerts (like N₂ or CO₂) or non-hydrocarbons (like H₂ or CO), since they do not exhibit a linear relationship between mass flow and "btu" flow. But if they are present in small quantities and don't vary much, the concept can still work.

On processes that degrade the "quality" of energy, Lou shares:

Saving energy can be as simple as minimizing thermodynamically irreversible operations. Mixing, heat transfer, and throttling of process flows are common examples of irreversible processes. In general, industry should avoid over-purifying/heating/cooling followed by mixing or blending to achieve the target composition/temperature. Process design should attempt to get as much work as possible out of utilities and recover as much heat as possible. Pinch technology is one approach to heat integration design used by process engineers. Of course, there are practical limitations like capital cost considerations, dynamic response and controllability, and availability/reliability of utilities, especially ambient cooling.

Also, control valves should be selected to minimize throttling losses and allocation and valve position should be used to minimize overall pressure drop in systems like utilities where resources are shared by different units or equipment. For example, if multiple reactors are cooled with a shared refrigeration unit, the coolant temperature setpoint can be raised (reducing the refrigeration required) until one of the user's demand exceeds the capability of its corresponding control valve to deliver.

Let's hope that something between the ChemicalProcessing.com article and Lou's thoughts provides you at least one idea that can help reduce your plant's energy bills.

My trusty Emerson RSS feed alerted me to a new liquid analysis application guide for the metals extraction and processing industry. This guide, published by Emerson's Rosemount Analytical Liquid business, covers the liquid analysis solutions for the following processes: leaching and ore extraction, concentration and separation, finished product purification and waste disposal.

I confess to knowing little about mining and metals production processes, but after reading this application guide, I have a much better appreciation for the processes and some of the challenges.

In the leaching and ore extraction section, precious metals such as gold and silver are commonly processed using cyanide compounds. As the guide succinctly puts it:

Cyanide dissolves the precious metal by forming a chemical complex with it, thus separating the precious metal from the other constituents of the ore, which do not dissolve.

The challenge is accurate pH measurement for both safety and efficiency. pH values lower than 11 favor the formation of hydrogen cyanide gas, which is colorless, odorless and poisonous in sufficient concentrations. Continuous pH monitoring and control is critical to prevent the formation of this gas. Measuring pH is complicated by the finely ground abrasive ore which can coat and abrade the pH sensor. The guide describes the Rosemount Analytical pH probe, jet spray cleaning attachment, and measurement analyzer best suited for this application.

The guide has easily understandable process flow diagrams for flotation cell pH measurement, titanium dioxide (TiO₂) manufacturing, Alumina/caustic ratio control, steel treating, cyanide oxidation and waste disposal via scrubbers. It provides a good overview description of the process, the measurement and control challenges, and the liquid analytical products that can help address these challenges.

If you're in the metals extraction and processing industry, this guide helps you understand the products Emerson offers for a particular application. For those of us not familiar with the industry, the guide provides a great overview of some of the major production processes and the challenges engineers from this industry face.

Given recent trends in metal prices, if you're a process automation engineer or engineering student, you may want to learn more about this industry. If you do, you'll find this guide to be a useful overview.

It's often difficult to understand the value a new international standard brings to your process manufacturing operations. Emerson's Jonas Berge has been hard at work in his capacity on the standards committee ISA104, Electronic Device Description Language (EDDL) to educate process automation professionals. In addition to the standards committee Jonas contributes his energy to the EDDL.org website and the EDDL email list. You can also see some of the other times I've featured his work.

His latest article, Temperature Transmitters: Warming Up to EDDL, in Industrial automation asia magazine, describes how enhancements to EDDL (a.k.a. IEC 61804-3) have improved setup and diagnostics of temperature transmitters.

Jonas describes how the technology in temperature transmitters has advanced to provide diagnosis of their health, the sensor wiring and the temperature-sensing element. This diagnostic information is communicated back to the asset management and/or automation system via digital protocols such as HART, WirelessHART and Foundation fieldbus.

An example Jonas offers is a temperature element burnout. The temperature device uses the EDDL standard to

...provide image displays, switched dynamically, that illustrate the problem.

Some of the more sophisticated temperature transmitters have dual sensing elements. Sensor drift can be determined and reported back to an operator or maintenance technician if a maximum difference is exceeded between the two measurements. These dual sensors can also operate in a hot-backup mode if they measure the same point. They are set in a primary/standby mode where failure of the primary sensor causes its value to be ignored and the backup sensor to be used.

Jonas also describes a loop-testing scenario typically performed by maintenance technicians:

Systems and software that fully implement IEC 61804-3 support EDDL wizards that take the technician through required steps to check the temperature transmitter as defined by its manufacturer.

The wizard reminds the technician to inform the operators that a loop test will be performed so the associated control loop can be changed to manual to prevent upsetting the process when temperature is simulated.

The EDDL standard provides a standard way for device manufacturers to embed help into these devices, which reduces learning hurdles for operators and maintenance techs to use these diagnostics.

Thanks to Rohit Kadam for pointing this story to me in his Nice To Meet You..! blog. Rohit is an active member in our DeltaV Twitter Community.

I received a sneak peak of a white paper in the works by Dr. José Gutierrez, corporate director of technology with Emerson. This paper, based on the Why WirelessHART? article, discusses diversity techniques to achieve the reliability design objectives in the WirelessHART standard.

José begins with some history of proprietary point-to-point wireless "cable replacement" solutions. Data transmission was required for these applications but cables were not economically feasible to install. These wireless solutions also typically were not designed to scale.

Process manufacturers have been under constant market pressure to improve efficiency and productivity. This pressure has spurred innovations by automation suppliers on numerous fronts including advanced diagnostic algorithms, improved sensor technologies and improved communications technologies especially in the area of wireless communications.

In the 1990s, the U.S. Defense department invested in wireless communications research with high reliability, highly secure and extremely low powered design objectives. This basic research fed into future developments by leading industrial and technology companies on the IEEE 802.15.4 radio-communications standard for wireless sensor and actuator applications. José served as chief technical editor of the IEEE 802.15.4 standard.

During this time in 2003, the HART Communications Foundation started its wireless efforts that culminated in the release of the WirelessHART standard in the fall of 2007. This standard is designed to support a range of applications including process monitoring, process control, equipment monitoring, environmental monitoring, energy management, asset management, predictive maintenance and advanced diagnostics.

What makes this range of applications possible is the advanced diversity techniques designed to achieve reliability greater than 99%. When best practices like three or more communications paths per device are applied, the reliability is significantly higher--approaching 100%.

The WirelessHART standard employs five methods of diversity: time, coding, frequency, path and power. Here's my brief summary of each from the white paper.

Time diversity involves the use of intelligent data transmission scheduling to minimize collisions and recover from losses. WirelessHART uses synchronized time division multiplexing.

Coding diversity uses the radio spectrum where specific transmissions can be separated from noise and other simultaneous communications.

Wireless devices use frequency diversity (a.k.a. channel hopping) to dynamically choose different communications frequencies to avoid jamming or to mitigate interference from other wireless systems.

Path diversity comes from the self-organizing, mesh-communications network formation of wireless devices in a point-to-multipoint fashion back to the automation system and/or asset management system.

The final diversity technique used in the WirelessHART standard is power diversity where radio power transmission is controlled to a minimum level to destination devices to cut down on radio frequency noise for other devices using the same frequency spectrum.

I hope some of this background helps give you an appreciation for the techniques used to achieve high wireless communications reliability. The proof comes by giving it a try in your plant on measurements not currently possible or practical to wire.

I read Siemens' Charles Fialkowski's latest post, Introducing a non-redundant, redundant SIL 3 solution? about their SIL 3 HART I/O card. He discusses how technology has changed where newer SIL-3 rated safety instrumented systems (SIS):

...don't require redundancy to achieve high levels of safety. In the past, safety systems required dual, triple or even quadruple redundancy just to achieve high levels of safety.

He points out that advances in technology have allowed diagnostic coverage not possible in earlier SIS designs. He closes his post:

Another common misunderstanding is how these systems address field redundancy (sensors and final control elements). While I can't speak for the Emerson or Yokogawa system, I do know for a fact that the new Siemens HART analog input module handles redundant field devices just like any dual, triple or quadruple redundant system would.

I thought I'd give the Emerson perspective so I caught up with DeltaV SIS product manager Mike Boudreaux. He first pointed out that DeltaV SIS has HART I/O and the DeltaV SIS logic solvers are SIL3 certified in simplex (non-redundant) mode and have been since DeltaV SIS began shipping in 2005. Other safety instrumented systems also accept HART I/O, but only to pass-through the HART data to asset management systems. DeltaV SIS makes this HART status information available in the logic solver.

Mike noted that only the analog, 4-20mA process variable (PV) is used for the safety instrumented function (SIF). The digital HART PV's are not accessible for use in SIFs, but the device status provided by the HART digital communications protocol is passed along with an analog input in DeltaV SIS. If a HART transmitter detects a problem, the status for an analog input will become "Bad." Conditions for a Bad status include earth leakage detection, loss of HART communications, device malfunction and device fixed-loop current to name a few.

This Bad status can be used in the logic solver. For example, in a multi-transmitter SIF, a voter block can be configured to ignore an input value if it is Bad. In accordance with the international safety standard IEC 61511, this capability can be used to provide continued safe operation of the process while the faulty part is repaired. DeltaV SIS will alert operations of this problem so that the device can be maintained in the specified mean time to repair (MTTR). Alternatively, the voter block can be configured to treat a detected failure as a vote to trip, which provides increased safety.

When a HART device detects a problem, an alert is displayed on the DeltaV operator station. SIS faceplates and detail displays for HART devices help operators view and manage HART device alarms.

DeltaV SIS also uses the HART communications protocol to enhance partial stroke testing. It validates the operation of the final control element--the most critical and most likely to fail in a safety instrumented function. The logic solver can generate HART commands to initiate a partial stroke test in a digital valve controller. The operators can initiate partial stroke tests manually from their operator workstations or they can be scheduled to occur automatically based on the specified test interval. The results from these tests are captured and integrated with the system event history. An alarm can be generated if a partial stroke test fails, alerting maintenance that there is a potential problem with a valve.

This diagnostic coverage and information feedback to operations provide process manufacturers better tools for compliance with the IEC 61511 safety lifecycle compliance efforts.

Update: Welcome readers of Gary Mintchell's Feed Forward blog. Thanks for the shout out, Gary!

Emerson's Dale Perry and Jonas Berge teamed up for a look at EDDL (Electronic Device Description Language) technology from a pressure measurement device perspective in a recent Industrial Automation Asia article, Pressure Transmitters: EDDL Equals Easy.

Their summation describes well why you might have an interest in this interoperability standard:

Given the breadth of transmitters and other field devices throughout process facilities, interoperability is essential for integration and ease of use. EDDL is the key to interoperability in a digital plant architecture as it merges functionality of devices using HART, Foundation fieldbus, or WirelessHART into the same single software structure so they can be managed together from a single dashboard.

Dale and Jonas describe the problem the enhanced EDDL standard addresses from the perspective of a pressure transmitter supplier:

Historically there was no display standardisation. The dilemma was that the pressure transmitter manufacturer could not dictate the system display or accessible transmitter functionality on a system.

It was primarily left up to the system vendor to create specialised screens that may or may not have included all the specialised functionality of pressure transmitter. It was not uncommon that devices that did not come from the system vendor itself was at a disadvantage.

The article highlights some of the information presented by Rosemount pressure transmitters via enhancements to the EDDL standard. The authors note that before these enhancements:

...there was no graphics for quick visualisation of the pressure transmitter diagnostic status nor could you look at the current PV and tell what the pressure was two minutes ago. And if the device had multiple variables there would be multiple numbers to look at and do math and correlation in your head.

The article displays and describes screen captures as seen in AMS Device Manager that supports enhanced EDDL including: trend charts, device diagnostic summary status, graphical gauges, detailed diagnostics, and even specialized charts that device suppliers can create. One Rosemount pressure transmitter example is a standard deviation chart showing process noise. In this case, it typically signals a plugged impulse line.

Dale and Jonas sum up the article by defining the responsibilities for both the device and software application providers:

Although the transmitter manufacturer controls what information is made available from the transmitter and how it is laid out on the screen, the look & feel details such as the appearance of buttons as well as activation of the help, printing, acceptances of changes, and comparison is handled by the device management software ensuring all devices work consistently regardless of manufacturer, type, or protocol.

Update: I updated the link to a PDF version of the article.

One way to reduce the sheer volume of email from those you work with is to promise to blog them. Most take this as an idle threat, so unfortunately the emails keep flowing. Here's a case where the threat is not idle, and here's the post to prove it.

The original question came in from a process manufacturer to ModelingAndControl.com's Greg McMillan and asked him for a recommended pH probe for low pH material (1-3pH). My hopefully trusty source, the pH entry in Wikipedia, puts that on a scale with gastric acid.

Greg contacted Dave Joseph, a senior industry manager in Emerson's Rosemount Analytical Liquid business. Dave responded:

In my experience, measuring low pH values in the 1-3 range is not very difficult. Although there is a nonlinear effect called "acid error", the primary source of error is junction potential due to the high concentration of H+. This manifests as a pH reading that ramps quickly into the ballpark but may take quite some time (100 secs or more) to get to the final value. It would be common for the reading to drop from 6 to 2.4 and then tick slowly down to 2.0, for instance. A good sensor for that kind of behavior is a more open junction like our PERpH-X design that allows the potential to stabilize quickly. It would also help cut the time necessary for calibration.

A clean ISFET [Ion-sensitive field effect transistor] sensor responds quickly regardless of the temperature, so the FET is an improvement for very low temperature processes (near 0°C) where high glass impedance causes slow response and noisy readings. In practice, most pH measurement issues have to do with the reference side of the sensor, which is subject to coating, plugging, poisoning, and junction potentials. pH applications can involve many different processes and conditions. Practically all of the troublesome measurements (high temperature, caustic (high pH), steam cleaning) for glass electrodes are even more problematic for ISFETs. In a low pH stream with no other concerns, an ISFET would be expected to function as well as a glass electrode, but with no specific advantages.

Greg's follow up question was:

Are there any hydration requirements for an ISFET? My understanding is that a glass electrode depends upon a hydrated gel layer.

Dave responded:

The glass electrode does use a hydrated gel layer to produce a stable potential. An ISFET works more directly and does not need hydration to make the measurement. That means that an ISFET may recover from a dry environment faster than a glass electrode would. However, both types of electrodes require a reference with a silver/silver chloride solution of water, and the presence of water in the process is required for acceptable continuous measurement.

I thought there was some wisdom in the exchange that needed to be set free from the clutches of my email inbox. Then again, let's see if Greg or Dave ever includes me on another email!

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.

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.

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.

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.

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.

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.

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 b