Asset Optimization

Emerson's Adam Lund has a great article, Human Centered Design Supports Improved Job Performance, in the February edition of Maintenance Technology magazine. Adam highlights some reasons why human centered design is growing in importance for process automation suppliers.

The rapid advancement of technology is breathtaking. Those like me with an affinity for gadgets follow the latest developments in Engadget and Gizmodo. While very cool and fun, Adam points to rapid technology advancement's downside for process automation professionals:

Years of professional analysis of industry work practices show that personnel are often overwhelmed with multiple systems and user interfaces, making it difficult to find critical information, especially while on a job in the field.

Technology's increasing capabilities and associated complexities are further heightened by the:

...demographic challenge as knowledgeable maintenance veterans retire and their places are taken by less experienced personnel.

Adam describes the human centered design (HCD) concept as being:

...aimed at identifying the information most needed by plant personnel and getting it to them in an easy-to-use format. This requires understanding the tasks frequently performed by end-users and presenting helpful information in a consistent fashion.

He describes the process in improving usability in the AMS Device Manager software and Emerson smart devices with familiar brand names such as Fisher, Rosemount, Micro Motion, CSI, DeltaV, Ovation, etc. Device dashboards in the AMS Device Manager were redesigned to:

...give workers an instant view of the critical items they need to evaluate, diagnose, and configure each device. Expert guidance is also provided to streamline the most important and frequently performed tasks by plant operations, engineering and maintenance personnel.

With the most common task performed by maintenance technicians identified, the software screens were reorganized into 3 primary areas: Overview, Configure, and Service Tools. This reorganization provides a quick glance when devices are working properly or not--and when not--highlights a path to quickly diagnose and troubleshoot the problem.

Much HCD work was performed on the smart device side to provide the same appearance to information coming from devices with different digital communications protocols including HART, WirelessHART, Foundation fieldbus, and Profibus. The device description (DD) varied widely among suppliers and different products within a single supplier. Emerson's Jonas Berge noted in an email to me that the IEC 61804-3 EDDL standard reduced this variation since the standard incorporates standard graphics. You can learn more about EDDL at the EDDL.org website and its email list.

Creating this common look and organization by task helps reduce complexity for maintenance technicians and allow them to:

...use the same procedures to manage devices regardless of communication protocol.

Beyond the Emerson brands mentioned in the article and this post, Jonas also noted the most automation suppliers support the IEC 61804-3 EDDL standard on the smart device side and the asset management and/or process automation system side.

The article describes how Emerson partner with Carnegie Mellon University to set a forward path in HCD. This work was the precursor to Emerson's creation of a Human Centered Design Institute. Adam describes it:

Emerson's new Human Centered Design Institute was established after more than five years of work-practice analysis, new product development re-engineering and organizational training. The Institute's goal is to bring about a significant improvement in ease-of-use and workforce productivity products that are reliable, compatible and cost-effective. User work practices and improved task completion (usability or workforce productivity) are at the heart of every new Emerson product.

The path going forward for all the technology developments across Emerson Process Management is to apply human center design concepts to reduce complexity and provide rapid discovery to its productivity-enhancing capabilities.

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Industrial Automation Insider's Andrew Bond wrote an article for ControlGlobal.com, DVCs Drive Digitization of the Process Industries. It describes the introduction of digital valve controllers by Emerson's Fisher business in the 1990s and their widespread use--more than one million FIELDVUE instruments sold.

One thing caught my eye:

Over the years increasing capability has been built into the Fisher device. Indeed the diagnostic capabilities of the latest version, the FIELDVUE DVC6000 Series, are such that Emerson claims that plants can operate for five to seven years between maintenance shutdowns.

Emerson's Danny Nelson was quoted in the article, so I asked if I could get more background on the 5-7 year statistic. Danny sent me a presentation by Ken Hall, whom you may recall from an earlier handheld device valve diagnostic post.

Manufacturers in many industries including refining, chemicals, and petrochemicals have extended their plant turnarounds (planned maintenance shutdown periods) from an annual event out to 5-7 years. Checking the performance of the control and shutdown valves is one of the key activities performed during these turnarounds.

Since the digital valve controllers have embedded diagnostics, the valves with these attached perform performance diagnostics on a continuous, non-intrusive basis. Their objective is to identify problems before they impact the process. Problem descriptions, possible causes, and recommended actions are provided back to the maintenance team through the asset management software.

Some of the conditions the diagnostics can uncover include supply pressure issues, I/P & relay integrity, travel deviation, and air mass flow for leak detection in actuators. Additional friction/dead band tests can help spot stem deformation, plug wear, packing issues, and trim damage.

Prior to these ongoing diagnostics, the valves would have to be pulled from service and looked over in the maintenance shop. Now they can be repaired proactively as the diagnostics report problems. This is one reason that plant turnaround lengths can be extended out to 5-7 years.

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Alain Pellegrino, a predictive maintenance technician with Emerson's local business partner Laurentide Controls, has a great article in ReliablePlant.com on resonance in plant equipment. The article, How to identify, correct a resonance condition, describes how resonance is a common cause in excessive machine vibration.

Resonant frequencies are something most all engineers face whether it is in electrical circuits, atomic bonds, process piping, road overpasses, or rotating machinery to name a few examples. Alain defines resonance:

...the result of an external force vibrating at the same frequency as the natural frequency of a system. Natural frequency is a characteristic of every machine, structure and even animals.

He describes techniques to identify resonant frequencies in plant equipment. The first is a simple, impact test, which is to strike the equipment being measured with a mass and measure the response. The mass delivers a small amount of force over a wide range of frequencies. The measurement occurs over the frequency range and identifies the frequencies where vibrations occur.

A more advanced test uses an "instrumented hammer." This has an accelerometer at one end of the hammer. A second sensor is on the piece of equipment being measured. Alain explains that you measure:

...the force induced to the system by the instrumented hammer and the response at different frequencies. When the phase shifts by 90 degrees, the frequency at which it occurs is a natural frequency.

This test not only can spot resonance problems, but additional ones such as imbalance, misalignment, and looseness. All of these conditions decrease the life of the equipment and can lead to unplanned downtime.

Another test Alain explains is the "coast down peak hold" which monitors the vibration level from operating region to shutdown. Without resonance, the expected vibration level drops at a steady rate. Otherwise:

If the vibration levels start rising at any time while the equipment is being shut down, the speed at which the amplitudes increase is a possible natural frequency.

A more sophisticated version of this test, coast down peak phase, monitors both vibration level and its phase shift while the equipment shuts down. This helps find the natural frequency, which is in the middle of the 180-degree phase shift.

So what do you do if your equipment has a resonant frequency somewhere in its operating range? Alain explains that natural frequency is a function of the equipment's stiffness and mass. To modify the natural frequency:

...either change the stiffness or the mass. Increasing the mass or lowering the stiffness will lower the natural frequency while reducing mass or increasing stiffness will increase natural frequency.

I know of some welders from my days offshore in the Gulf of Mexico who would be excited at the opportunity to weld on some additional mass or stiffener brackets, but these solutions are not always possible or practical. If you can do it, the easiest way is to change the operating speed 20-30% from the natural frequency.

Another possible solution Alain describes:

...install a dynamic absorber on the equipment to significantly reduce the vibration levels of the equipment. The dynamic absorber is a spring-mass system that is installed in series with the resonant system to create an out-of-phase exciting force to effectively counteract the initial exciting force.

Alain sums up his thoughts by stressing the need to use at least two of the tests to identify and confirm the resonant frequencies before taking action to impact the mass, stiffness, operating speed, or vibration absorption.

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Handheld field communicators have been the tool of maintenance technicians to configure and calibrate their smart field devices since the 1980s. With technology advancements and by taking a fresh look at handheld usability with a lens on the problems maintenance techs were trying to solve--the Emerson team developed a new application.

I caught wind of this application, ValveLink Mobile, which is included in the 475 and 375 Field Communicators with the v3.2 software and the Easy Upgrade utility. I went the source, Emerson's Ken Hall, for a download of what maintenance technicians might find useful in their day-to-day work. Ken is a software product-marketing manager for the Fisher FIELDVUE team.

For those unfamiliar with AMS ValveLink software, it allows maintenance and operations folks to monitor control valve health and performance online and spot problems before they affect the process. Ken pointed out the news of more than one million FIELDVUE digital valve controllers sold, so that's quite a number of valves to check on. Many are not connected on-line to an asset management software package such as AMS Device Manager or to a control system such as the DeltaV system. The way to communicate with these digital valve controllers is through the handheld device.

What maintenance techs were missing from these handheld devices was the ability to perform advanced diagnostics tests to see if the valve was sticking, sluggish, leaking, etc. These problems can impact the performance of the process, cause variability in what's being produced, or even lead to unplanned shutdowns. These tests could be done with ruggedized PCs rated for the valve's location with the AMS ValveLink software, but this approach was not ideal from a usability perspective. This is especially the case if the maintenance tech were on a ladder, catwalk, or other difficult position.

The ValveLink and AMS technologists worked to bring a subset of this functionality to the 375 and 475 handhelds, and even to Windows Mobile-based smart phones connected to the DVC6200 and DVC6000 controllers with a Bluetooth HART modem. The ValveLink Mobile software had to be accessible by a finger or thumb on the touch screen.

For the DVC6000 controller installed with the higher-level diagnostics, this application can perform tests such as valve signatures, dynamic error bands, and valve stroking. In fact, Ken noted that the tech can see the diagnostic graph built in real-time to spot where the problem might be occurring. When combined with the visual and audio feedback from being near the valve, this can help get to the root cause more quickly.

Ken also noted that the diagnostic tests performed on the handheld or smart phone can be downloaded back to the AMS Device Manager using Bluetooth, IrDA, or SD memory. Initially this application supports the HART-based DVC6200 and DVC6000 controllers and future versions will support Foundation fieldbus, the DVC2000 and DVC6000 SIS.

Here's a 3 ½-minute "silent-movie" video, which shows the diagnostics running on the handheld device and Windows Mobile smart phone.

Given the control valve's importance in the performance of the process, bringing these diagnostics into the hands of the maintenance technicians can go a long way in reducing abnormal situations, excessive variability, and unplanned shutdowns.

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Emerson's Alan Harris has written a new whitepaper, DeltaV SIS HART Capabilities. It describes various HART capabilities that can be used with the DeltaV SIS system as well as HART diagnostics implementation best practices. For those unfamiliar with HART, the HART Communications Foundation describes it:

HART (Highway Addressable Remote Transducer) Protocol is the global standard for sending and receiving digital information across analog wires between smart devices and control or monitoring system.

Alan describes the importance of HART diagnostics in safety applications:

The HART diagnostics provide much more information on the health of a field device than can be determined from a standard 4-20 mA signal. For this reason, greater SIL (by turning Dangerous Undetected failures into Dangerous Detected failures) and longer proof testing intervals can be achieved by field devices running HART diagnostics.

He also makes the strong point that HART is not a safety-rated platform and that you should never substitute HART signals for hardwired signals, when the hardwired signal is being used to detect a hazardous condition with a SIL (safety integrity level) rating. HART only should be used for diagnostic purposes.

Alan does describe ways it can be used, especially in safety instrumented systems like DeltaV SIS that can incorporate these diagnostics directly into the SIS logic. One example is upon recognition of sensor faulty status; the SIS logic can degrade the transmitter voting:

...remove the transmitter from the voting logic (i.e. a 2oo3 voted group of transmitters degrades to 1oo2 or 2oo2 with the bad transmitter viewed as faulty) or the transmitter can be simply alarmed via operator graphics.

In the case of a problem with a final control element with a HART-enabled digital valve controller:

...HART device status signals can be used to trip valves that use a HART-enabled positioner or alarm the valve via operator graphics.

Other conditions the SIS logic can monitor in sensor devices through the HART diagnostics include PV out of limits, analog-digital mismatch, PV output saturated, PV output fixed, loss of digital communications, and field device malfunction.

For safety-application rated digital valve controllers like the Fisher DVC6000 SIS, diagnostics available to the SIS logic or asset management software include: loop current, auxiliary contact status, output pressure, % travel, position, drive signal, valve setpoint, pressure, differential pressure, and DVC internal temperature. Also, this digital communications provides a path for the SIS logic or asset management software to initiate manual or scheduled partial stroke tests (PST), which:

...checks for valve movement without fully stroking the valve. Many applications will allow 10% movements to verify valve response without upsetting the critical process line. Diagnostic data is collected and an alert is given if the valve is stuck.

Alan's whitepaper describes some of the diagnostics available in other Emerson devices such as the Rosemount 3051S pressure and 3144P temperature transmitters, and the Micro Motion Coriolis flow transmitters. He describes the purpose of these diagnostics to give the reader ideas of how they might be incorporated into their SIS logic to improve diagnostic coverage and safely increase overall availability by reducing spurious trips.

If you're responsible for your plant's safety instrumented system, you might consider giving this whitepaper a read.

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You have to love the march of technology as it applies to handheld devices, such as smart phones. Calling, texting, tweeting, emailing, web browsing all continue to get easier. In our world of process automation, technology also advances, although not quite at the same pace. Automation suppliers need to contend with explosive and corrosive environments. To be successfully used in these environments, extensive testing and certification for intrinsically safe operation with agencies such as CENELEC/ATEX, FM, CSA, FISCO, IECEx, etc. is required.

I mention all this because a new Emerson handheld device, the 475 Field Communicator, is coming on to the scene. These handhelds began years ago with the 268 HART Communicator in the mid 1980s, the 275 HART Communicator in the early 1990s and the 375 Field Communicator in the early 2000s.

The first thing an instrumentation professional will notice in the 475 is the color display. In prior EDDL-related posts, I discussed how this standard provides a form and structure for automation systems and handheld communicators to access and display device diagnostic and setup information. The 475 color display makes these diagnostic and setup screens more quickly recognized and understood.

The other big thing is full support for HART 7, which includes WirelessHART. The 475 provides configuration, device diagnostics, and advanced troubleshooting for HART, Foundation fieldbus, and WirelessHART devices.

I asked brand manager, Alan Dewey, to name some other key improvements over the 375. The size and weight are reduced to make it easier to carry and use around the plant. Battery life doubles both in use and in standby. Alan mentioned that usability was also a focus for the design team and they reduced boot up time and device display call up times.

With Bluetooth becoming prevalent in PCs, it made sense for the 475 technology team to add this protocol to provide fast, secure data transfer with the AMS Device Manager application on the PC and the Easy Upgrade Utility (which helps users keep their communicator up-to-date with the latest system software and device drivers). Like the 375, Infrared (IrDA) communications is also available, but the transfer rate is doubled.

I hope to see a few "YouTube unboxing" videos out in the wild as instrumentation folks get their hands on these. You can bet I'll have my RSS search going to be on the lookout!

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Update: Added link to the 475 Field Communicator site.

One of the best parts of authoring the Emerson Process Experts blog is some of the conversations that follow in phone calls and emails. These can happen even years after a post has been published. A good example is one that sparked from the post, What is Your Reactive Maintenance Percentage?

I received an email asking some great questions:

I just read your short but interestingly accurate article entitled, "What is Your Reactive Maintenance Percentage?" and am wondering if you've done any further studies relative to ROI? I'm kicking around coming up with percentages to work within the following areas:

1. Repairs (reactive) vs. preventive maintenance: I've found one mention that a savings of 30-35% can be had in operational costs due to unscheduled parts, labor or vendor cost. For example, not maintaining a machine gearbox by changing the lube cartridge can cost upwards of $20k to refurb it, vs. a minimal monthly labor fee to inspect and keep up on lubrication requirements.
2. Increased productivity: In other words, giving "focus" to labor being spent, sometimes on a standby basis, for problems that might come up. This is an area we CAN put a number on. Based on time and motion studies I've done in manufacturing-type industries, I believe a PM program, using a very conservative estimate of saving 1 hour per day for 1 employee calculates to: 1 hour/day x 5 hours/week x 52 weeks/year x $70/hour (burdened) = $18,200 per year. Multiply this by a couple more employees and you have a fairly substantial ROI to play with.

Any thoughts?

I went back to Emerson's Bill Broussard, whose expertise I had cited in the original post. Here's a portion of his response emailed back:

The ROI equation, I have found, ultimately has to take a metric that eliminates the emotions involved around a piece of equipment or operational area.

What I have found to work are a few things. And my perspective, honestly, is to help folks who bought our technology continue to get the value from it.

First, we look at apps where an end user has already made an investment in any kind of predictive technology. We take a group of assets, say 200, and go to their CMMS (work Order management system), take a period of time (we often use 6 months, but 12 works as well), and pull from this system the total number of work orders executed against these assets. The CMMS system typically tags the WO [work order] as emergent or planned. So, from there, it is easy to benchmark the planned versus reactive effort for the site.

Second, for sites that either are in the FEED / Design stage, or for brown fields that are trying to figure out how to stop the 'fire fighting mode', we apply an asset criticality ranking. This process is a groupthink approach driven by someone who has done it before. It is often effective from a 'change culture' perspective to have an external influencer to drive the meeting discussion. Once complete, the rank on top critical assets suddenly is material and in front of everyone. This then allows a 'how do these assets fail' discussion to take place, and out of that discussion comes the 'how do I rationalize investments in predictive intelligence', and frankly, the whole predictive / proactive allocation approach.

So, in summary, it is the asset's criticality to the operation that should drive the ROI discussion.

Here's an article I wrote recently on this process, Integrating Asset Management and Maintenance. Emerson is starting to utilize this process in our own FEED efforts.

I've mentioned in the past that there is quite a bit of wisdom trapped in all of our email inboxes and sent items folders. I hope digging an occasional one out helps others with similar questions.

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What's that expression... "Tan, rested, and ready"? After a nice holiday break filled with family, friends, and football (I'm in Texas after all!), it's time for me to dive back into the business of highlighting experts around Emerson Process Management.

I read a great piece in the AppliedAutomation supplement in the November 2008 issue of Plant Engineering magazine entitled, Asset management leverages smart wireless devices. Laura Briggs and Joseph Citrano, both managers in the Asset Optimization business, wrote this article.

Laura and Joseph made the point that all of the diagnostics that process manufacturers get from their HART devices connected to their asset management software or HART-enabled automation systems are also available from WirelessHART devices. They describe how Emerson's AMS Device Manager software has two-way communications through a wireless gateway to communicate this diagnostic information between the wireless devices and the asset management software.

Prior generation wireless devices used in monitoring applications typically did not support two-way communications. They would broadcast process variable information but not any associated diagnostics. Verifying the accuracy of the transmitted information required a trip by a plant technician to the device. For devices located in hazardous areas, this might also require work permits and sniffers to measure explosive gas concentrations. The authors note that the process typically takes a few hours and often no problems are found.

This troubleshooting process for both wired and wireless devices can take place in the maintenance shop or other area where the PC with asset management software is located. While devices with actual problems must still require the work permit, gas sniffers and other safety procedures, the "no problem found" instances can be eliminated.

Laura and Joseph also describe how this information can be used as part of a predictive maintenance program. Repair and replace decisions can be made based on the diagnostic trends from the devices. Also, device calibration schedules and device maintenance documentation for both the wired and wireless devices can be managed centrally.

The article highlights a wireless application at a PPG facility where wireless devices were used where it was too cost-prohibitive to run wire and conduit (estimated to cost $20 per foot.) The wireless network "came to life" five minutes after installing it.

To me, it sounds like a good thing to be quick to install, provide process information where none existed before, and provide diagnostics to simplify ongoing maintenance.

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Update: I was reminded of a great video Joseph has done showing the setup, management, and use of best practices for your wireless network using the AMS Device Manager.

Update: I made one clarification above that the article appeared in the AppliedAutomation supplement that came with the Plant Engineering supplement.

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!

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

The controlled chaos that surrounds a plant turnaround, or planned shutdown, has given more than a few engineers some gray hair. I highlighted a plant turnaround planning presentation at last year's Emerson Exchange and I asked Emerson's Chris Forland if I could get this year's presentation.

Chris, Scott Grunwald, and Miranda Pilrose presented, Parts, People Process: The Winning Formula for Emerson Turnarounds and Certified Services.

Some of the challenges causing the gray hairs to sprout include the loss of experienced folks to plan and execute the turnarounds. You can also count on finding things during the turnaround that you did not expect. You might also miss finding hidden problems during the turnaround that manifest themselves once you've started the process up again.

The turnaround period is also a golden opportunity to look for optimization opportunities to reduce energy consumption and improve process efficiency.

Chris, Scott and Miranda stressed the need to address these challenges head on by starting the planning process early--since the plan flexibility decreases as the turnaround start date approaches. It's likely that any investment in pre-turnaround planning and equipment analysis will rapidly pay itself back in improved performance.

They describe a six-step turnaround program that includes project kick-off, condition assessment, refining the details, internal planning, turnaround execution, and post-turnaround review.

The project kickoff step defines the scope of outages, personnel, roles and mission of the Emerson turnaround team. The turnaround project plan is thoroughly reviewed, maintenance records are reviewed, and the timing, duration, and budget are scoped. The team conducts a detailed plant walk-down to familiarize everyone with the facility and the challenges.

The condition assessment step looks for control performance issues while the plant is still running. It identifies equipment, control strategies and process dynamics that need to be addressed during the turnaround.

In the refining the details step, internal valve conditions are analyzed with Flowscanner and AMS ValveLink, process dynamics are measured with the Entech Toolkit, and gap analysis is performed to find opportunities for integrating with other plant software like computerized maintenance management system (CMMS) software. Another key activity is to review the plant's use of diagnostics in turnaround planning and maintenance.

Turnaround execution--the time of controlled chaos--is made more manageable because only the valves that need work are removed. Since the conditions are known ahead of time, the necessary repair parts can be on hand and work performed to a pre-planned schedule. During this period of frequent communication among turnaround team members, status reports are updated and changes to the turnaround plan are documented and rescheduled as required. Equipment asset performance is returned to OEM specification with the necessary ASME conformance and FM Approvals documented. Predictive diagnostic technologies can also be installed and commissioned during this step. Finally, per the measured process dynamics, tuning and control strategy adjustments are made to optimize the performance of the process.

The post-turnaround step captures and documents what was learned throughout the planning and execution--for the next turnaround that will likely include many new team members from the process manufacturer's staff. Budget items are reconciled, improvements documented, asset repair reports assembled, valve diagnostic curves archived, and baselines generated for ongoing performance analysis. The information is assembled into a final documentation package and reviewed at the post-turnaround review meeting. It's also important to quantify the improvements to verify the value of the time and resources that went into this extensive planning and execution process.

As part of the team, Emerson brings expertise from many areas including instrument & valve services, electrical reliability, and control system performance due to the wide-ranging skills required to perform a successful turnaround.

The key is to identify, plan and schedule as much as possible--as early as possible--to minimize the unplanned, gray-hair producing moments.

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The ISA recently issued a press release around demonstrations of Electronic Device Description Language, EDDL (international standard IEC61804 and ANSI/ISA-61804-3) and FDT (ISA103) technologies at the ISA Expo 2008 in October in Houston, Texas.

For those not familiar with EDDL, I described it in an earlier post as a text-based language that is used to describe the characteristics of field devices. Following the EDDL standard, device suppliers create Electronic Device Description (EDD) files for their smart field devices. These files provide a standardized form and structure for automation systems and handheld communicators to access and display device diagnostic and setup information, independent of communication protocol or operating system.

Emerson's Terry Blevins has been working closely with other automation suppliers on the EDDL demonstration. He also is the ISA104 committee chairman. This committee has adopted the EDDL standard, IEC61804, as an ANSI/ISA standard. The release describes what will be shown in the ISA104 booth at ISA EXPO 2008:

The ISA104 EDDL booth at ISA EXPO 2008 is a demonstration by major DCS manufacturers such as Invensys, ABB, Siemens and Emerson that illustrates the technical strengths of the EDDL standard, IEC61804, to support advanced user interfaces for diagnostics and device setup independent of the communication technology support by the device. Devices such as valve position[er]s based on HART, Foundation Fieldbus, and Profibus from Metso, Samson, Invensys, Fisher Controls, and Siemens are used to illustrate how manufacturers are using EDDL to document their device capabilities in a single, open and consistent format. A live demonstration of diagnostic information being accessed using a WirelessHART adapter connected to a wired HART device and through wireless access to a self-powered WirelessHART device illustrates how EDDL supports the latest wireless devices.

The demonstration provides the exhibit attendees the opportunity to see the advanced interfaces for device diagnostics and device setup that are available from the major DCS manufacturers that use device EDD's. This demonstration will also show how the EDDL technology is by DCS supplier to provide interfaces to support wireless devices based on the WirelessHART standard.

In the release, Terry and the ISA104 committee also describe recent activities to continue to advance the IEC61804 standard:

International Electrotechnical Commission's Technical Committee 65 (IEC TC65) met in Tokyo, Japan, the week of 18 May. The working group responsible for the EDDL international standard, IEC SC65E WG7, met on 20 May and discussed future EDDL enhancements that will be incorporated into the existing standard, IEC61804. A number of guests from Japan and China that attended the WG7 meeting expressed an interest in learning more about EDDL. Thus, following the WG7 meeting, Christian Diedrich and Terry Blevins put on a workshop that provided more detail on EDDL and showed examples of how EDDL is used to write device descriptions.

If your plans include Houston the 14-16^th of October, make sure to stop by and visit with Terry and the other automation suppliers to see how this standard provides a common, interoperable way to present smart device information to you.

In several parts of the world including North America, Emerson Process Management sells some of its products and services through local business partners. I came across a great Pulp & Paper magazine article, Control Valve Management Can Pay Off Big, written by Jeff Klatt. Jeff is with one of these local business partners, R.E. Mason.

Jeff recounted his experiences as a large paper mill's asset manager. What struck me about the article were not the technologies they ultimately applied, but rather his systematic approach to process improvement. I'll highlight some of the steps he recounts in the article to see if they might spur some ideas for improvement in your operations.

Jeff cited a study conducted by Emerson's Fisher Valve business that found that 80% of the control valves used by process manufacturers were not operating within their optimum parameters. Getting process improvements by addressing these was a large part of last week's post, Start with the Basics to Reduce Process Variability.

He described his initial step:

It seemed logical to first get acquainted with the valves in the mill and understand their roles in the papermaking process. One-by-one, I visited valves throughout the three main sections of the mill -utilities, fibers and product (papermaking) - documenting every one and building a personal database. Identifying, locating, and visually inspecting nearly 1,600 control valves in the mill turned out to be a monumental task that took months to complete.

Through this tedious process, he also engaged operations, which:

...explained which control loops had the greatest effect on product quality, productivity, and safety/environmental considerations. This knowledge was essential in establishing the most important valves, and in the end about 25% of all the valves were prioritized as critical to the mill's mission. These became the valves on which the majority of maintenance attention was focused.

As is often the case, this tedious work lays the foundation for future savings. He also had all the storerooms spare parts identified, tagged and catalogued. This effort allowed greater use of existing stock and fewer purchases of new parts, which improved the mill's working capital. In one year alone, 20 good control valves taken out of service and put into one of the storerooms were returned into service saving $55,000 (USD) in cost.

The prioritization of the critical control valves also provided focus on where to apply the technologies to improve the performance of the process. Jeff and team used the Flowscanner tool to find out more about the condition of the highest priority valves to direct the maintenance efforts. Also, digital valve controllers were added to these critical control valves over time to provide real-time diagnostics with the AMS software to begin a program of predictive maintenance. A valve's signature can be compared with its baseline performance to identify problems. These can be addressed before actual failures or variability-creating conditions occur. Jeff's team documented $50,000 a year in maintenance cost savings.

Jeff highlighted other savings such as a valve variability problem on a CIO2 flow valve being identified and addressed resulting in an annual savings of a $140,000. Another was documenting the useful lifecycle extension of 162 tested valves by an average of two years. Calculated cost savings were $86,000.

While the savings are impressive because they reoccur over time, the approach is what I found instructional. It started with a commitment to focus time and energy on these control valves because of their critical role in the process. Next was the discipline to analyze the current state and work with operations to identify the most critical control valves. This process laid the groundwork for the application of some of the technologies described to achieve lower costs and greater efficiency. From Jeff's quantified results, it appears this focus paid dividends.

I had the opportunity to visit with Emerson's Tom Wallace who was here in Austin recently. I like to joke with Tom that a post I had done with him comparing and contrasting HART and Foundation fieldbus caused such a stir, that it produced one of this blog's highest monthly visitor totals to date.

So let's see what we can do this month! Tom takes a comparative look at some of the swirl that surrounds EDDL and FDT/DTM in a new paper, FDT/DTM, and Enhanced EDDL, what's best for the user. These are both technology enablers for field devices, automation systems and asset management applications.

If this is all acronym soup to you, here's Tom's brief description of these technology enablers:

Device functionality is invoked using Electronic Device Description Language, EDDL or DTM's [Device Type Manager]. The DD or DTM tells the host what functionality the device has, and how the functionality is invoked. It also tells the host how to do common maintenance functions such as calibration, trims, tests, and other device activities.

I'll start with Tom's conclusion and then highlight some of his supporting points. He concludes:

In my opinion, there is a better technical implementation based primarily on ease of implementation and support. That solution is to use EDDL for all devices where EDDL is technically capable of delivering complete device functionality, and to use a DTM or a snap-on application to handle only the exceptions. I make this recommendation because it is simpler to implement a single solution than a combined solution. EDDL is a single solution that will work for the vast majority (95%) of HART, Foundation fieldbus, and Profibus PA devices.

Tom's point for commissioning Foundation fieldbus devices contrasts installable programs versus data files:

Commissioning Foundation fieldbus devices on most control hosts require DD's [device descriptions]. Most control hosts have a set list of applications that are considered safe to install on the host engineering or operator station. Each DTM is an application, and the testing required to ensure hundreds, or potentially thousands of DTM's are compatible with a control host user interface is not practical. EDD's are files, not application programs. Therefore there is no program installation risk loading EDD's on a control host.

On data availability, Tom writes:

...EDDL is the path for data availability that originates from a device, or is going to a device. The OPC Foundation support for the enhanced EDDL will broaden the use of EDDL for applications such as ERP, maintenance management, and other applications.

For the display of data in field devices, Tom notes:

EDDL is supported in the host by DD services. DTM is supported in the host by a frame or FDT. For many applications and hosts either EDDL or DTM can be used for data display. For hosts that are not based on a windows operating system, EDDL will be used as DTM requires a windows operating system. EDDL has defined display objects such as charts, graphs, etc. DTM is more of a free form environment using a variety of programming languages.

The choice for the enabler technology to use is EDDL or a combination of EDDL and DTM. Tom lists some considerations for your discussion based on operating systems, operating system version management, functionality and complexity of the device and if a custom display needs to be created.

Tom sums all this up with the following recommendation:

The final recommendation is to use EDDL as the required standard since each device must have a DD. Allow the use of DTM's on an exception basis where the functionality is required, and EDDL cannot provide it. Make sure that all the functionality to replace a failed device, or place a new device in service is available in EDDL. This will simplify implementation and maintenance, mitigate operating system migration issues, and provide a lower risk more error free working environment.

Update: Welcome readers of Gary Mintchell's Feed Forward blog! Join the conversation and add your comments below or on Gary's post.

In my days as a young automation engineer putting in power, control, and safety systems on offshore oil and gas platforms, I had the "opportunity" to see improperly terminated motor leads burn up during a startup after power was supplied to them from a variable speed drive. So, it was with great interest that I listened to a presentation during the Emerson Exchange by Wally Vahlstrom and Cliff Kirby in Emerson's Electrical Reliability Services organization. I could have used their expertise back then to prevent that sinking feeling I had when I smelled smoke.

Their presentation, Early Detection of MV Cable Problems Improves Overall System Reliability, described how failures can occur and steps to diagnose impending failures.

Cable terminations and splices are the area where most prone to deterioration and failure since these are typically assembled by hand. The junctions account for 80 percent of the failures. Typical problems include nicked insulation, incorrectly connected or no drain wire, physical abuse, and environmental contamination-all of which can produce partial discharge (PD). Also, voltage transients caused by lightning and other sources, and manufacturing defects can create reliability problems.

Cables themselves can also fail caused by many things including manufacturing defects, damage caused by installation or physical abuse, metallic shield corrosion, water migration, and even cable test methods like DC Hi-Pot methods which can damage older cables. Typically, the cable will pass the test, but fail after AC power is reapplied after some period. There are many suspected reasons for this but one may be that 'space charges' develop in the insulation during application of the DC test voltage.

Wally discussed a form of deterioration known as water trees found in extruded dielectric cables. These trees are water-filled micro channels that develop in the insulation of cables operating in a wet environment. The patterns that form resemble trees that have lost their leaves. Water trees can continue to grow under operating voltage until they bridge the insulation. This often leads to cable failure.

Cliff discussed some of the US standards and guides for testing cables in the field. IEEE 400 warns against testing the cable using DC Hi-Pot methods on older medium voltage cables, especially in wet environments because it accelerates failure. Other test methods described by the IEEE 400 standard include AC Hi-Pot, Partial Discharge, Very Low Frequency (VLF), Dissipation Factor (Tan delta) and Oscillating Wave (OSW).

The Electrical Reliability Services team uses on-line partial discharge detection methods to test the reliability of the cable system. It is the only test of the ones mentioned that can be performed while the cable is energized and in service. This testing method is a non-destructive, non-invasive predictive maintenance tool that assesses aging cables. This test is also used to test for workmanship in new cable installations, given the 80% failures occurring around the handmade terminations and splices. Ah yes, this is what triggered my memory of those smoking motor terminations!

A spectrum analyzer, RF analyzer, and U-shaped sensor are used to identify partial discharge. This testing can see about 500 feet each way down a cable.

Cliff showed some installations with corrosion in other areas outside of the cables including medium voltage switchgear. Typically, this is caused by non-operational space heaters in the switchgear. These space heaters prevent condensation that causes this corrosion to occur.

Cliff recommends a site assessment be done which can be performed over time. What to assess should be based on criticality, past failure rates, and environmental conditions to prioritize how and where the partial discharge testing is done.

Update: I've removed the picture and associated text for the picture I incorrectly attributed to IEEE.

I recently joined the Electronic Device Description Language (EDDL) mailing list to follow the work of this important standard. For those not familiar with this standard, EDDL.org describes it:

Electronic Device Description Language (EDDL) technology is used by major manufacturers to describe the information that is accessible in digital devices. Electronic device descriptions are available for over 15 million devices that are currently installed in the process industry. The technology is used by the major process control systems and maintenance tool suppliers to support device diagnostics and calibration.

In prior posts, I've discussed how this text-based standard makes the exchange of information from smart field devices and maintenance software and/or automation systems easy so that information from different suppliers field devices can be presented to you in a common way. These smart field devices are based on the popular digital communications protocols HART, Foundation fieldbus and Profibus. EDDL can theoretically be used with any protocol. The standard declares device parameters and their dependencies, visual representations, user interactions, and how systems access information.

Emerson's Jonas Berge is an active participant in EDDL and the ISA104 Committee and recently posted a summary of activities that I thought I'd share:

BIS test find EDDL meets NAMUR NE 105

EDDL Workshop, Frankfurt Germany, 8 April 2008

ISA Electronic Device Description Interoperability Guideline Gains ANSI Approval

ISA Electronic Device Description Gains ANSI Approval

Recent Articles
EDDL makes Foundation fieldbus easier

EDDL: Unlocking Device Information

EDDL allows interoperability for devices to constantly gather information

News/Events Archive
EDDL demo and presentation at CIA2007 in Singapore 27-30 November

ISA104 explains EDDL at ISA EXPO 2007

EDDL demo and presentation in Japan in November 2007

EDDL demo and presentation in Singapore in November 2007

Forum
Make sure your colleagues involved with bus technology and intelligent device management also join this EDDL forum. There will be more important announcements shortly.

Jonas noted to me that the first link to the BIS test (BIS Prozesstechnik--subsidiary of Bilfinger Berger Industrial Services) used devices and control systems from different suppliers to see if the EDDL meets the requirements in NAMUR recommendation 105 for field device integration in engineering tools. This tested the IEC 61804-3 standard and how it is used by device and control system manufacturers, and the advantages the new EDDL standard has for plants in the commissioning, operation, and maintenance phases of the lifecycle.

The test is described:

A wide range of device types were tested including everything from the simple temperature and pressure transmitters to sophisticated radar level transmitters, valve positioners, and frequency converters (variable speed drive) connected via HART, FOUNDATION fieldbus, PROFIBUS DP and PROFIBUS PA bus systems.

Findings include:

The study found that EDDL meet the requirements also for complex devices, further software tools are not required. EDDL wizards, images, and trend charts enable good usability and intuitive operation also for complex use cases (e.g. Partial Stroke Tests).

Jonas and those involved in the EDDL standards effort have been quite busy in communicating their activities. I hope this post helps bring some additional visibility to these efforts.

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.

Automation World magazine's editor in chief, Gary Mintchell, wrote a post yesterday on his Feed Forward blog. The post, The Saga Continues - FDT v EDDL describes some of his discussions with people involved in both groups about the relative merits of their respective approaches to smart device communications. Lest I be accused of tossing around acronyms too casually, EDDL stands for Electronic Device Description Language and FDT stands for Field Device Tool.

Because I subscribe to Gary's RSS feed with Outlook 2007, I was able to forward his post much like an email message to Emerson's Terry Blevins and Tom Wallace for their views. Here is the text of their comments posted on the Feed Forward site.

From Terry:

Gary, It is good to see your interest in EDDL. As you may be aware, EDDL is the international electronic device description language standard for the process industry (IEC 61804).

Through the work of the ISA SP104 committee the IEC61804 standard was officially adopted last year as an ISA/ANSI standard. The SP104 committee worked with ISA to establish the www.eddl.org web site. At this web site you will find information on the benefits of EDDL and the advantages that EDDL has over other technologies.

In particular, you may find the paper and the tutorial that the SP104 committee presented at ISA2007 EXPO to be of help in examining this topic in more detail - please see www.eddl.org/files/ISA2007_EDDLTutorial_Presentation.pdf and www.eddl.org/files/ISA2007_EDDLTutorial_Paper.pdf.

Best regards,

Terry Blevins
Chair, SP104

From Tom:

Gary,

First, some good comments from you, thanks. I have a few thoughts to add to yours. First is a technical clarification. EDDL is the language used to write DD's. The DD is not in the device, it's in the host. Next, FDT/DTM is not used by any control host to my knowledge. It's used for asset management, therefore it's not in the DCS, the DCS usually is the path for information from the field to the FDT application. Regarding differences, because EDDL is operating system agnostic, DD's written using EDDL can reside in a handheld. FDT/DTM requires a PC level Windows operating system. As such, it won't work on devices that use an embedded operating systems such as linex, or Windows CE. Also, control hosts frequently use DD's. For example, Yokogawa CENTUM CS3000 uses EDD's to understand and use the capability of FF field devices. To my knowledge, DTM's are not used in this way. The net result is that the user will need DD's for intrinsically safe handhelds, and will in many cases also need DD's for the control host to correctly function with FF devices.

DD's will provide the functionality to perform maintenance functions on just about any HART, FF, or Profibus PA device in existence. Adding FDT/DTM where it's not needed adds to end user maintenance cost and time. Both EDD's and DTM's must be installed and maintained. Why add maintenance work if it's not needed? In addition, EDD's have been forward compatible for many years. What this means is that if a user installs a newer version of device to their plant, an older DD will work with the newer device. It may not know about enhanced functionality in the newer device, but it will perform the basics of configuration and maintenance. When it's 2AM and you're trying to avoid a shutdown, or get the plant back up, the last thing you want is to find you don't have the latest configuration file you need to configure your device. Although DTM's could be written to be forward compatible, to date most are not. I recommend users of FDT/DTM have a complete set of DD's available and on tools they use regularly so they can avoid this potential problem. There are some cases where EDDL is not sufficient, and a supplementary technology is needed. Some devices require calculation capability beyond that provided by EDDL for initial device setup. These devices usually have a separate Windows based configuration program already available to provide the added capability. DTM's have potential use here, but alternate solutions already exist. At this point I think that DD's will always be in the plant, and DD's will continue to be needed to perform functions and in environments that FDT/DTM cannot serve. One other issue I'm seeing with FDT/DTM is that it is not being used as a complementary technology to EDDL, it's being used as a replacement for EDDL to perform functions that have been and will continue to be completely supported with EDDL. These functions include device configuration and maintenance for devices that have been completely supported by DD's in the past, and continue to be completely supportable by EDDL or enhanced EDDL today. Since EDDL is an IEC standard, I am concerned about FDT/DTM, or any technology that is being used to move users away from standards, especially since the standard, EDDL will provide all the functionality needed for the vast majority of devices in all plants worldwide today. Another concern is that FDT/DTM may be slowing the implementation of the full functionality of EDDL in host systems. As such, it's not a complementary technology, but a competing one. Finally, I'd like to make a recommendation for the end user community. It strongly aligns with your recommendations, but has some additional points. The first is that the end user community encourage their host vendors to fully implement all the features supported by EDDL in their hosts. The second is that the end user community encourage their host vendors to move with speed and dedication toward the solution being worked by the EDDL / FDT/DTM working group. When this solution is available it should provide the best of both EDDL and FDT/DTM. The third is that I recommend the end user community use EDDL as their standard solution and add FDT/DTM on an exception basis. Since FDT/DTM is being positioned as a complementary technology to EDDL, I encourage the end user community to use it that way. Use FDT/DTM only if and where it provides needed functionality that is not available through EDDL.

Although I am strongly pro-EDDL, and cautious about FDT/DTM, I hope these comments have some merit, and you will consider posting them.

Thanks and regards,

Tom Wallace

If you have thoughts to share, join the conversation on the Feed Forward site or here.

The Automation List on Control.com recently had a question about IMC Tuning for Integrated Processes. I googled around for IMC or internal model control for a good definition and found these 2002 Introduction to Robust Control lecture notes:

The Internal Model Control (IMC) philosophy relies on the Internal Model Principle, which states that control can be achieved only if the control system encapsulates, either implicitly or explicitly, some representation of the process to be controlled.

The Automation List question asked how IMC can be implemented if the process time constant, process gain, control integral and controller gain are unknown. This person did a manual step test on the drum level feedwater control valve and the drum level starts to integrate (rise.) Measuring this occurrence provides dead time, level rate of change and change in control valve position.

The questioner writes:

I know you can implement Lambda Tuning, but from what I've seen with this, you end up with a very sluggish system that responds quite poorly due to the low value of Kc (please don't comment here on 3 element control, as this is not apart of the discussion).

Am I missing something here, or have other people used different methods?

We've had several posts in the past on Lambda tuning, so I forwarded this question to Mark Coughran, a senior control engineering consultant on the Advanced Applied Technology team.

Mark notes:

Whatever method you use, it is important to understand each of the terms in the equations and the appropriate units of measure. Training is available to make clear how to measure the process dynamics, choose Lambda, and calculate the controller gain and reset. Emerson Educational Services offers the courses Process Dynamics, Control and Tuning Fundamentals (9030) and Modern Loop Tuning (9032). Tools and on-site services are also available.

Lambda tuning simply means the loop will not oscillate and you choose the speed of closed-loop response (Lambda), within some reasonable constraints. There is no reason to believe that Lambda tuning is arbitrarily "slow" or "fast", since you choose the Lambda.

ZN or Ziegler-Nichols is a method to deliberately make the loop oscillate. This is not a good idea in any process plant.

I've highlighted the topic of plant turnarounds (planned downtime for maintenance) a few times in the past. Back from the Emerson Exchange, here's my take on the Smart Turnaround workshop. For continuous processes that run for years, this turnaround provides opportunity to update, fix, repair, and replace a host of plant assets including instruments, valves, electrical distribution equipment, connectors and cabling, and the overall performance of the process.

The Emerson presenters looked at the advanced planning that can be done from these various perspectives. From these diverse areas of expertise, diagnostic testing helps develop a turnaround plan that prioritizes critical asset work, defines the scope of work, develops the schedule for the work, and identifies the parts and people required to best get this difficult work done.

Chris Forland an operations consultant whose work I've highlighted in earlier posts kicked off the session discussing some of the challenges of the turnaround process. A big one is finding problems you didn't expect while in the turnaround. These unexpected problems cause extra charges and delays. Chris discussed ways that Emerson turnaround specialists can help with the detailed planning to make sure the work is efficiently performed during the turnaround. He noted that less time to plan mean less flexibility as the turnaround date approaches. Other challenges included maintaining compliance with safety and regulatory compliance, working with budget constraints, reducing process variability, losing experienced personnel due to infrequency of turnarounds, and pressuring of short turnarounds due to sold out condition of produced product.

Scott Grunwald, a turnaround business manager in the Instrument & Valve Services business, recommended that with the valves and instruments, you start by building the plan based on the benefits to be achieved the roles of all participants in the maintenance activities, and the prioritized list of activities and anticipated timelines. The process starts with a walk down of the facility. Next, FlowScanner is used to measure internal valve conditions to identify problems to address during the turnaround. When it's time for executing the turnaround, only valves needing significant work are removed. Other valves are repaired in place.

The team often brings an on-sight mobile trailer that is a self-contained workshop to rework the instrument and valves right on-site. This helps to expedite the repair process.

Looking at turnarounds from an electrical reliability perspective, Steve Metzger described the goal--to prioritize and focus the resources by pre-diagnosing troubleshooting, followed by the planning of the repair services and parts required to get the lead times properly. The key is to do as much pre-work as possible, fix what's possible, and remove it from the scope of the turnaround to lessen the pile of work to be done.

On-line partial discharge testing before the turnaround detects cables with degrading insulation that could cause short circuits and unexpected downtime. This testing helps determine which cables are OK and which need to be replaced during the turnaround.

James Beall, also highlighted in earlier posts, summed up the goal of a Smart Turnaround--to identify the items you can fix in advance, and prioritize what can't be in the turnaround plan. James and the variability management consultants look at the control performance and opportunities to reduce process variability through better tuning. James gave an example of a mixing temperature control loop where the deadtime was nine minutes between a change in setpoint and response the temperature was changing. The problem was not in the loop tuning but rather in the lag caused by the temperature transmitter being located 250 feet from where it should have been. Finding this early in the process allowed this installation mistake to be scheduled and fixed during the turnaround.

Chris closed this presentation with how you can look at the return on investment to help justify the experts required to make the planning and execution of the turnaround a success. It's a bit of a chicken and egg scenario since you don't know what type of ROI this turnaround planning can create without having the experts come in to begin the process of identifying improvement opportunities.

Chris has developed a model based on turnaround experience with typical costs from each of the aspects of turnaround planning and typical costs for the maintenance activities. This model is in an excel spreadsheets so that the assumptions can be easily changed to fit the unique aspects of each process manufacturer. Both cost avoidance and increased revenue from improved plant performance is calculated, each based on the size of the process and amount of equipment considered.

By taking a comprehensive planning approach, and getting an early start, turnarounds do not have to cause quite the number of gray hairs that they have traditionally been known to cause.

Update: Mitzi Amon, director of marketing for Emerson Electrical Reliability Services team adds that the prioritization is accomplished by performing online diagnostic testing prior to the turnaround to determine what electrical equipment needs to be serviced during the turnaround. This helps clearly define maintenance work scope during the turnaround and what can be done prior to the the turnaround.

Bill Broussard, a marketing manager in the Machinery Health Management part of Emerson's Asset Optimization business, recently had an article published in Plant Engineering magazine. The article, Act, don't react, for greater asset optimization, suggests a path away from operating in the world of reactive maintenance toward planned maintenance.

Process manufacturing is a very complex business with lots of things that can go wrong at any point in time. Bill describes how leading process manufacturers in highly effective maintenance programs spend less than 10% of their total maintenance responding to unexpected failures or "fire fighting" as some folks colorfully refer to it.

These leading manufacturers will spend around 80% of their time performing "planned" maintenance activities. He states more specifically, 25-35% on preventative maintenance activities, 45-55% on predictive maintenance activities, and the balance on proactive maintenance.

The analogy I'd draw is that of a car. The predictive part is responding to the intelligent sensors that provide early warning of an impending problem. The preventative part is doing the oil change every several thousand miles or kilometers. The proactive part is changing out components without embedded intelligence (like belts) at fixed mileage intervals. The reactive part is calling the tow truck when you have the hood up and smoke coming out alongside the road. I don't know about you, but reactive is my least favorite. It means lost time, high cost, and inconvenience figuring out what to do next.

Bill makes the case that process manufacturers who spend a larger percentage of time "reacting" than the best also experience higher costs and lost revenue. In the article, he states:

This reactive nature can be illustrated by considering an everyday occurrence: an operator sees a perplexing issue on the control system console but usually cannot leave the post to investigate. Maintenance is called to check it out, and this becomes a reactive work request - new work that was unplanned. It is a wasteful and potentially expensive use of resources, which is why those who lead their industries in operational excellence operate mostly in a planned rather than reactive environment.

Bill recommends that the shift from reactive to planned maintenance begin with creating an asset optimization culture that focuses predictive maintenance on key production assets. Cultural change is not always an easy thing, so he recommends:

...bringing in asset optimization consultants to identify areas for greatest potential to improve availability and performance. Through proven methods that evaluate the base of critical production assets, experts typically develop a prioritized asset list, which later becomes a part of a larger strategic roadmap for achieving asset optimization goals.

He cites a number of process manufacturers who have reduced downtime and maintenance costs by shifting over time their maintenance programs from reactive to planned maintenance. If your reactive maintenance percentages are higher than the leading process manufacturers' percentages, it might make sense to review the business case for change and bringing in a fresh set of eyes to help.

...Better that, than waiting for the tow truck!

The ARC Advisory Group's Wil Chin has an industry trends report published today on Emerson's Asset Optimization group. The report, Emerson Asset Optimization Division Enhances Solutions, looks at the technologies and expertise this plant asset management (PAM) space. I've added hyperlinks in some of the quotes where more information is available.

In the area of plant connectivity with business systems the reports states:

...the Asset Optimization Division continues to add AMS Device Manager connection options to simplify the implementation of PAM solutions, such as wireless device connectivity, Profibus/HART interfaces, and motor starters and drives solutions.

Wireless smart field devices, a growing area of interest, is described:

...wireless field devices based on the soon to be released WirelessHART standard, which is now supported by virtually all automation systems and field device suppliers. ARC believes wireless field devices provide a low-cost conduit for accessing stranded diagnostic information to enable PAM solutions, and it is a low risk first step for manufacturers to experience wireless technology.

The wealth of diagnostics from smart field devices can take some thought on how to incorporate because:

...users struggled with updating hard-to-change maintenance practices despite their best intentions. Because the plant workforce is multitasking to the max, few available resources could be applied to the implementation and management of new technologies and best practices. PlantWeb Services were introduced to help clients get the most out of PAM investments.

Asset prioritization was one of the services cited:

...users want to know which of the asset health alerts are critical, ranked in importance to the performance goals of the enterprise. Asset Prioritization provides a systematic methodology combined with the domain experience of Emerson's professionals to quickly prioritize assets into a Maintenance Priority Index (MPI). The index is determined in a six step process that considers business criteria, asset criticality, operational criticality, probability factors and others to determine the MPI.

Machinery health was a final area described in the report:

...Machinery Health Management solutions consisting of high-end portable machinery health analyzers, machinery health transmitters, machinery health monitors and machinery performance monitors, which all integrate with the AMS Suite predictive diagnostics application, including to Emerson's Ovation and DeltaV control systems.

The combination of technologies to monitor the production process assets combined with experts who can work with process manufacturers to incorporate this diagnostic information into work practices provides a way to improve performance.

I received a call recently from an automation engineer facing an upcoming planned shutdown or "turnaround" in industry parlance. Actually "controlled chaos" may be a better moniker since a tremendous amount of maintenance activity needs to be squeezed into a short period. This engineer had come across one of my earlier posts on this topic and was looking for help in analyzing the control performance of the process control loops prior to the turnaround. This analysis helps identify control issues that can be addressed during the turnaround.

Time is money when the plant is not in production, so this time must be carefully planned and methodically executed to get all the maintenance activities done without schedule delays. Large refineries, petrochemical plants and other continuous processes will run for years between turnarounds. This means there are often new people working each one, which adds to the challenge.

Chris Forland, whom you may recall from earlier posts, reminded me that planning could extend beyond control loop performance to include a plan for the control valves and other plant assets.

Emerson's Asset Optimization team has developed a smart turnaround program, which puts a primary focus on control valves but also includes instruments, rotating machinery, and power distribution assets. The program includes a pre-turnaround planning and analysis phase, turnaround execution phase, post-turnaround review phase, and an ongoing maintenance phase.

The post-turnaround review phase captures the results versus the plan and documents the baseline and best practices to serve as "institutional memory" for the next time a turnaround is scheduled and new personnel are involved. Documentation to support on-going maintenance after the turnaround is also reviewed and submitted.

Chris recommended that planning should begin six to twelve months in advance since the flexibility to make changes to the plan diminishes as the turnaround date approaches. This investment in pre-turnaround planning and equipment analysis will be offset by avoidance of delays during the turnaround, reduced turnaround cost, and more efficient operations post-turnaround from better performing assets.

Turnaround specialists review diagnostics from smart instruments based on Foundation fieldbus and HART digital communications to determine which control valves actually need to be pulled for service. Portable diagnostic equipment can be brought in if smart instruments are not in place. Chris notes that typically only 70% of these valves need to be pulled and serviced.

This program ranges from a cost reduction only focus where units are already performing optimally, to a production performance improvement level, to a level of sustaining high performance through training of plant operations and maintenance staff to more effectively use diagnostics from smart instruments.

If your plant conducts turnarounds from time to time and if are going to the Emerson Exchange next month in Dallas, make sure to check out the sessions on smart turnarounds.

A colleague pointed me to an article, Timeline of a refinery pump failure and how it could have been prevented, on the Belgium-based EngineeringNet.be website. The story was about a South American refinery that had a high-speed centrifugal pump fail catastrophically resulting in production losses and large repair costs. Todd Reeves is in Emerson's Machinery Health Management team, part of the Asset Optimization organization.

What happened was an inboard bearing lost lubrication, overheated and finally seized up. The unfortunate part of the story is an automated motor-pump train monitor and advanced vibration analysis system had been installed four months earlier and was working properly.

This monitoring equipment included the CSI 9210 Machinery Health Transmitter connected to the automation system via Foundation fieldbus. This equipment did its job communicating advisory alarms it began to detect problems in the lubrication system.

These alerts went unheeded until they became maintenance alerts and ultimately failure alerts. Todd wrote that the health curve of the pump deteriorated rapidly in the final ten minutes before failure.

Why? The equipment did its job and dutifully reported the problem. The issue turned out to be more of overall unit tuning and alarm management issues. These alerts had been lost among other alarms coming in.

Working as a team, the refinery and local asset optimization experts reviewed the overall alarm strategy and identified opportunities to reduce the alarms and alerts coming in to the operators.

Specifically for the pumps, a best practice was established to add additional temperature measurements on the pump. Training was established to clarify how these alerts would be transitioned between the operators and maintenance staff. Clarifying this process is important when working with predictive diagnostics. At the time, it is not yet an actual problem--but like this centrifugal pump example--will fail if not addressed.

As reported in the Sound OFF! Editors' Blog, the ISA issued a press release announced that the ISA-SP104 committee has completed adoption of EDDL as an ANSI standard specified by IEC 61804. It is now: ANSI/ISA-61804-3 (1004.00.01)-2007, Function Blocks (FB) for Process Control - Part 3: Electronic Device Description Language (EDDL).

So if you are an automation engineer you might ask... so what? I have attempted to address this "so what?" question in prior posts, but it is something I will try again in my quest to simplify in my mind--if not yours.

The best way I can think of it is a text-based file that is associated with your smart Foundation fieldbus, HART, or some of your PROFIBUS devices in your plant. This text-based file presents its operation, diagnostic, performance analysis, operating statistics, calibration and other information in a standard, globally agreed upon way. Applications like your control system, asset management software and handheld devices that support this standard can present the information to you in a standard, intuitive way.

The analogy I have used in the past is the Really Simple Syndication (RSS) standard for publishing and consuming information across the web. Like the smart field devices, web news feeds, blogs, and other RSS-enabled content provide their information in this agreed upon global data standard. You can use RSS readers like my favorite, Google Reader, to read the information to which you choose to subscribe.

Continuing the analogy, your RSS reader presents this information to you in a common way--the look, the fonts, the shortcut keys, etc. The content can come from different suppliers' web servers, be on different operating systems, and even run with different software applications that create these standards-based RSS files.

Likewise, your application that understands the global EDDL standard (like Emerson's AMS Device Manager and 375 Field Communicator) can present the information from various smart field devices, from different suppliers, and even running different digital communications protocols. As ISA-SP104 Committee Chair (and fellow blogger), Terry Blevins said in the release:

Using tools based on EDDL can mean faster device commissioning and loop checkout, as well as reduced field trips and the elimination of unnecessary maintenance.

In an earlier post, I had mentioned the ISA-SP104 committee had established an EDDL.ORG site as an educational site. The committee has been hard at work creating educational information including basic information, participating organizations in this standard, and other news, events, and technical resources.

And, as reported this past April, the EDDL team and another smart device-based standard, FDT Group, agreed to combine efforts and work toward a unified solution for device integration that is compatible with both technologies. ARC Advisory Group sums up this collaborative effort well:

ARC applauds the collaboration efforts of the parties involved. The actions of this group will be remembered as the tipping point where practical common standards for field device integration were founded. Working toward the singular goal of easy equipment configuration and management will provide more value than anyone could have imagined.

Recently, Flow Control magazine published an article by Gerry Berry, a metallurgical engineer working with Emerson's Micro Motion Coriolis flowmeters. The article, Strategies for Proper Material Selection--Lessons Learned from 30 Years of Application Experience, shares considerations in selecting materials suitable for reliable fluid handling systems.

The article gleans a few key nuggets from the comprehensive Micro Motion Corrosion Guide and describes this guide as:

a repository of test data that has been accumulating over decades of testing and field experience with customers on hundreds of thousands of applications.

Over the years, Gerry and the team have used tools such as x-ray equipment, positive material identification (PMI), scanning electron microscopes, ultrasonic thickness measuring devices, Hall-Effect gauges, potententiostats, and hardness and microhardness testers to accumulate this valuable test data. The team also takes advantage of the National Association of Corrosion Engineers' (NACE) body of knowledge.

For those like me who may not be versed on the subject of corrosion, the article provides an excellent overview on corrosion and its causes and begins with a good definition:

Corrosion is the degradation of a metal or alloy caused by its reaction with an environment. Metals and alloys rely on the formation of an oxide layer for protection. The integrity of the oxide layer is dependent upon both the metal and the environment. For reliable protection, the oxide layer must be uniform.

Gerry provides several fundamental questions you need to ask to assess material compatibility:

• What corrosive agents are in the process and in what concentration range?
• What is the process temperature range?
• What material is being used for the piping?
• What cleaning cycles exist, and what fluids are used in these cycles?
• What is the velocity (particularly important when handling sulfuric acid)?

After addressing these questions, there are process-specific considerations like erosion caused by solids, liquid slurry, or even gaseous steam moving through a pipe at high velocity. Also, as I can attest from my earlier years on the oil and gas platforms in the Gulf of Mexico, humidity, salt water and other ambient environmental conditions must be considered. For processes requiring sterilization between batches, the clean-in-place/sterilize-in-place operations, the draining capabilities of the piping, and dwell time between batches should be considered.

Gerry provides some other scenarios like processes with chlorine, fluorine, changing chemical mixtures, and large temperature swings and the challenges they bring from a corrosion standpoint.

If your responsibilities include the selection of materials for your instrumentation, I highly recommend the article and the wealth of great information in the Corrosion Guide.

In an earlier post, I discussed maintaining compliance of hazardous area certified equipment, from a paper given by Emerson safety consultant, Bob Baker.

At the recent AIChE Spring National Meeting Process Plant Safety Symposium, Bob gave an updated paper, Safety & Regulatory Compliance of Reconditioned Equipment (presentation).

He sums up the pressures that process manufacturers face:

Responding to challenges of seemingly unending reductions in capital and maintenance budgets, the process industry has increasingly turned toward the purchase of lower cost, recycled equipment including salvaged control valves and instrumentation.

The market for salvaged and reconditioned control valves expanded from onshore and offshore oil and gas producers in the early 1990s to onshore chemical, petrochemical and refiners today due in large part to declining maintenance budgets and financial pressure on small, locally engineered capital projects.

Unless appropriate equipment purchase specifications are specified and followed, exposure to potentially significant safety risks may occur when using salvaged, new-surplus, refurbished, or remanufactured equipment (considered "reconditioned" equipment):

Although it equipment may be acceptable from a functional perspective, depending on equipment age, repair history, application severity and other factors, such "reconditioned" equipment may be out of compliance with safety standards, or with manufacturer's specifications as originally designed to applicable industry codes, for safe use in hazardous locations.

One of the U.S. Occupational Health and Safety Administration (OSHA)-accredited Nationally Recognized Testing Laboratory (NRTL) is FM Approvals. The paper notes that FM Approvals' position for reconditioned and new-surplus instruments for use in hazardous locations:

It is FM Approvals' position that only the original manufacturer of the Approved product or an FM Approved remanufacturer whose facilities are part of the FM Approvals follow-up audit program, can remanufacture a product and reissue the FM Approvals certification mark. Any suggestion, practice or inference to the contrary is wrong and must cease... Any salvaged, remanufactured or new surplus electrical instrument cannot be labeled or relabeled as FM Approved for use in a classified hazardous location unless the refurbishing/new surplus supplier entity is audited and approved by FM Approvals, LLC, for that specific type of instrument.

FM Approvals presented the issues, challenges, and its position at several safety symposiums in late 2006 and early 2007.

Bob offers this recommendation for process manufacturers:

Vendor qualification and technical awareness is critical, requiring initial education of all plant personnel associated with the specification, purchase, inspection or repair of reconditioned and new-surplus equipment. Further, ever-changing organizational structure and new personnel requires a sustained education program, including ongoing emphasis at safety meetings. End user issuance of specific corporate policy and guidance could be an effective method to appropriately emphasize and establish requirements for purchasing reconditioned equipment.

Regulatory organizations such as OSHA and EPA typically put the burden of sustaining compliance to safety and regulatory requirements on the end user.

If you are using or considering using "reconditioned" instrumentation in hazardous locations or "reconditioned" control valves in applications within your plant's Process Safety Management (PSM) program, make sure to read the entire paper. Bob provides suggestions for vendor qualification requirements, suggests work processes, and describes the applicable standards.

Here is another in my series of screencasts, this time showing how an automation system uses predictive maintenance diagnostics to switchover a pump before it fails.

Emerson's DeltaV product manager, Randy Balentine, shows in this 2 minute, 43 second screencast a redundant pair of pump-motor trains. These pump-motor trains are being monitored with CSI 9210 Machinery Health Transmitters.

Randy shows a situation where one of the transmitters communicates excessive vibration via Foundation fieldbus digital communications to a DeltaV system. One of the DeltaV control modules receives the diagnostic alert, performs the logic to switchover to the backup pump-motor train, and notifies the operator of the problem so that it can be addressed.

By incorporating these predictive diagnostics into the control strategy, the switchover can happen before a failure causes a loss of production. Based on the severity of the diagnostic information reported by the smart Foundation fieldbus transmitter, the actions can range from notification of the operators to control actions performed by the control strategy.

I recently came across a lubricant analysis story in Plant Services magazine about an electric power provider in Kansas in the U.S. It described how this producer wanted to reduce costs and improve machine reliability. The article described the importance of comprehensive oil analysis and the decision to do analysis in house with Emerson's CSI 5200 minilab versus sending the samples offsite.

I caught up with Ray Garvey, an engineer in the Machinery Health Management organization about this project. Ray said that Mark Mayworm and the team at Westar's Jeffrey Energy have configured a solution that is ideally suited for this collection of six power plants. Westar is one example of the truth in Drew Troyer's words:

Every successful oil analysis program I have observed has passionate technicians performing the work. And almost without exception, each includes some degree of onsite oil analysis.

Ray is convinced that a combination of these two things: passionate technicians and some degree of onsite oil analysis have produced a successful lubrication program for Westar.

Ray mentioned other documented cases, who like Mark Mayworm, have followed this lube program success formula and it has paid off:

Jaime Viramontes and others supporting El Paso Electric's PdM program achieved cost avoidance of $8.8 million over a period of three years. Jaime reports, "The oil analysis program has been a successful and integral part of EPEC's PdM/RBM program."

Ed Bohn documented 738% Return on investment with 2 month payback period for investment in minilab and training by General Motors.

Dennis Roinick and the entire PdM Team at Duke McGuire nuclear station won "Best Overall Predictive Maintenance Program" in Uptime's Program of the Year competition in recognition for their fully integrated program which includes an on-site minilab.

Herb Springer gives this reason for the reliability success resulting from on-site oil analysis at each of more than a dozen Southern Company plants, "The results I get from doing onsite oil analysis are more representative of the health of the machine at that moment."

Richard Kus of American Axle and Manufacturing found savings of $75,000 to $100,000 using on-site oil analysis.

Mike Lenz and others from P&H Minepro Services transport their minilabs to the mine sites as one part of their predictive diagnostic services in North and South America.

These folks and many others are Ray's heroes. Each in their own way is a champion for the cause of better lubrication practices in their diverse plant situations. Ray confided with me that he was one of a dozen developers who set out in 1991 to design cost-effective on-site oil analysis solutions and then to build credibility for those solutions.

For an engineer and inventor like Ray, there is a huge personal reward every time one of these "passionate technicians" calls in to say, "Hey, this is great! Let me tell you what I was able to find using your onsite minilab..."

ARC Advisory Group's Larry O'Brien provides an excellent article entitled Briefing: Emerson's Process Management's Asset Optimization Business. He summarizes the services of the Asset Optimization business this way:

The AO business is divided into the two primary segments of Asset Reliability Services and PlantWeb Services, and the former encompasses Emerson's traditional MRO services business, including services for control valves and instrumentation, as well as mechanical and electrical equipment. The Asset Reliability Services business covers testing, diagnostics, repair, calibration, and maintenance including spare parts and reconditioned equipment. Managing and executing plant turnarounds is also a core capability of Emerson.

PlantWeb Services are dedicated to the successful implementation and use of AMS Suite software and the predictive diagnostics technologies of Emerson's PlantWeb digital plant architecture. Emerson has PlantWeb Service engineers worldwide dedicated to tasks such as opportunity assessment and benchmarking, asset prioritization, technology implementation, training, and extending PlantWeb installations to other realms of operations and maintenance, such as machinery health management.

Emerson is the market leader for PAM [plant asset management] applications, and they realize that they must provide a strong business value proposition for AMS to remain successful. The key to success for any PAM implementation is planning, planning, and more planning. This means offering a comprehensive set of services around AMS that allow users to get the most out of the application and put it in the context of a strategy for operational excellence and continuous improvement.