Plant Equipment

The big news today is the unveiling of the $30 million Emerson Innovation Center to advance Fisher technology in Marshalltown, Iowa. From the release:

The world's appetite for energy is driving the development of next-generation nuclear plants, mega-train liquefied natural gas (LNG) plants, and large oil and gas refineries, which require larger capacities and highly engineered control valves and instrumentation. The 136,000-square-foot Emerson Innovation Center is designed to help companies deliver record volumes of natural gas and other forms of energy and consume less in the process, reducing costs and making plants run quieter and with reduced greenhouse emissions.

The center is home to the world's largest "flow lab" that, for the first time, enables large valves to be tested in real-world plant conditions to ensure production reliability, efficiency, environmental compliance, and safety before being installed at a customer site.

I'm not at the big event, but I've been following the action closely in Twitter and on blogs such as Gary Mintchell's Feed Forward blog and Eoin Ó Riain's Read-out Instrumentation Signpost blog.

Sound Off! Editors' Blog's Walt Boyes is sharing real-time photos of the lab using his TweetPhoto and Facebook accounts. You can see pictures of a noise testing assembly, acoustic lab-noise reduction technologies, and a Westinghouse safety cooling valve on test as well as some of the event's presenters. These pictures help bring to life what those of us not there, can see.

Just to give you a flavor for some of the news being shared in Twitter:

garymintchell: Emerson lab also used for testing to develop products with lower noise emission for quieter plants.

kyleyleger: Smalltown pride, company pride & individual pride & ownership is the strong foundation of our business. -Buzbee #EMR

garymintchell: Ed Monser Emerson Corp COO - it's a big deal for me for this investment to be here. Finest collection of valve engineers on planet.

waltboyes: Friction test uses new human centered design http://tweetphoto.com/21998256

kyleyleger: Grand opening includes 7 demonstrations of never been done before Fisher technology. Demos presented by industry leading experts. #EMR

Having events like these unfold in real-time through the social media channels provides those not in attendance with a way to follow the action.

We're starting the planning process for this year's Emerson Exchange event Sep 27 through Oct 1 in San Antonio to add social media components for the benefit of both those who can attend and those who can't join us in person.

MP3 | iTunes

Update: Gary Mintchell adds more this morning on yesterday's event in today's post, Emerson's Innovation Center Opening.

OK, I confess to being an engineer in my core when I was explaining to my son the other day how the heart is a reciprocating pump. The systolic and diastolic pressures are the high and low-pressure peaks based on the heart's expansion/contraction cycle. Blood pressure is one diagnostic indicator on the health of the heart and circulatory system.

What prompted me to remember all this was a presentation I'm looking at by Emerson's Tim Olsen. You may recall Tim from his successful election to the position of 2nd Vice Chair for the AIChE Fuels & Petrochemicals Division (FPD). The subject of the presentation is pump health monitoring.

Thankfully, Tim did not take this heart analogy path we find ourselves on in this post. Typically, a process pump failure will cause a process upset and loss of production. If the pump is pumping flammable or hazardous substances and has a seal failure, safety, health, and environmental issues may occur. Having a spare in-line pump does not prevent unexpected failures that may result in conditions requiring prompt operator attention.

Without monitoring, pump seal failures often appear to be sudden and indicated by spills, vapor clouds, or fires. Today, for most process pumps, warnings come from periodic manual vibration measurement. Tim shares that most refiners monitor their critical pumps, perhaps 5% of all the pumps. The definition of what is critical is likely similar across refiners, but there will be differences.

Both safety and economic reasons are considered when identifying critical pumps. Every pump, critical or not, can cause pains such as process upsets and increased maintenance costs. For this reason, pump health monitoring may be warranted on many "non-critical" pumps. In the case of refiners, Tim cites a pump failure example, which can lead to insufficient fractionator reflux causing column overhead system over-pressuring. This in turn leads to the lifting of a relief valve to flare.

Tim recommends adding wireless measurements in places where existing diagnostic instrumentation is not present. He has observed three key areas that refiners are looking at pump monitoring capabilities: alkylation units, critical workhorse units like the crude unit, fluid catalytic cracking (FCC), and hydrocracker, as well as those applications with a history of unexpected pump failures.

Continuous vibration monitoring is important to identify and prevent root causes of seal failure from occurring. Some causes of this vibration include poor shaft alignment, worn bearings, loose pump mounts, broken foundation mounting bolts, cracked foundation, cracked or damaged impeller, and cavitation. This excessive vibration increases the wear on the pump's mechanical seal leading to failure.

Replacing the field operator or maintenance technician's manual spot measurements with continuous measurements provides the information to predict when failures will likely occur to allow maintenance to be performed before a failure occurs. This information can be historized and trended and made available in real-time to both console operators and maintenance departments. Wireless vibration transmitters form the heart of a health monitoring solution that is secure and easy to implement.

Tim makes the point that that having pump health monitoring is like adding sets of eyes continuously focused on these pumps, providing operators the opportunity to take corrective action before the pump failure. This early warning can help avoid the associated health, safety, and environmental impacts.

Pump health monitoring as part of an overall predictive maintenance program can deliver financial returns. In a Chemical Processing article, More-intelligent devices help plants get smarter, Emerson's Doug White noted:

Actual implementations of predictive maintenance have led to significant gains... Potential production from existing equipment typically increases 1-3% because of fewer unscheduled shutdowns, while unplanned maintenance costs decrease 10-30%. The return on investment can be among the highest of any possible plant expenditure...

Although this may admittedly be a stretch, the cost of pump health monitoring is perhaps like the cost of good nutrition and exercise for maintaining a healthy heart.

MP3 | iTunes

Last week, I shared how resonance can contribute to excessive machine vibration in the post, Spotting and Fixing Resonance in Plant Equipment. A colleague pointed me toward another true Emerson Expert, Dr. Allen Fagerlund. Al's expertise is on noise measurement and prediction. He also serves on the ISA75, Control Valve Standards and its subcommittee, ISA75.07, Control Valve Noise Measurement and Prediction.

I came across a paper that he and colleagues had written a few years ago, Identification and Prediction of Piping System Noise. It describes how various components in a plant's piping system can be sources of noise. The piping system forms a network through the facility, with sound waves radiating through this network. The authors describe this noise:

In an ideal sense, noise generated by any component or source will propagate in the fluid and cause the pipe wall to vibrate, with subsequent radiation from the outer surface to an observation point. In reality there also can be a direct structureborne path from the source to the pipe which adds to both the vibration level and to the radiated noise.

For flowing, incompressible liquids:

Generally liquid noise is not a problem unless cavitation [formation of vapor bubbles] occurs somewhere in a system. Since the noise from cavitation is an indicator of potential damage to piping and equipment, it has been more important to develop guidelines to prevent cavitation than to develop methods to predict the level of the noise.

I know from my days on offshore platforms that high-pressure natural gas piping was a large source of noise. Compressible fluid flows are potential sources of noise across a broad frequency range. The authors note that structural resonance is typically checked in the system design phase, but acoustic resonance may not be. The fix:

...is either to eliminate or change the frequency of the source tone or to decouple the resonance, whichever is most efficient and/or effective. Broadband noise can also excite system resonances which makes decoupling more difficult. Reducing the source noise levels are the main option.

Sources of noise include turbulent flow of compressible fluids, changes in pipe diameter, termination of piping at a manifold or vessel, and noise induced by equipment such as, "Compressors, valves, orifices, area expansions, spargers, etc..."

Some automation suppliers provide noise prediction for their equipment. Al is part of the Fisher Valve division, which has a noise prediction section in the Control Valve Handbook. Unfortunately, other piping components don't have methods to predict noise levels. The authors reference the work, VDI 3733:

...a compendium of information on the noise generated by piping systems. The influence of piping components as well as piping configurations are examined and presented in a quick calculation style without having to work through a detailed explanation of the phenomenon involved. Its broad subject coverage makes it a unique reference.

The problem with broadband sources of noise is that their frequency range can include resonant frequencies of the piping. Noise at these resonant frequencies can cause acoustic fatigue, which is structural fatigue of the pipe wall from high-amplitude vibration. The authors point out:

Acoustic fatigue is generally not a concern for external noise levels below 110dB for unlagged piping (acoustically insulating the pipe to reduce noise levels below 110dB will not reduce the fatigue risk since the pipe is still vibrating with the same amplitude).

Al is applying his expertise in the new Marshalltown flow lab, where the team has built an extensive noise-abatement testing lab to continue to advance the science of ways to reduce acoustical noise in plants.

MP3 | iTunes

Update:I received an email that the link to the article was not working. It is working for me. Here's an alternative link to the article to a Google Docs version that worked for the person who emailed me. If you have troubles with the original link, let me know if this alternative link also does not work.

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.

MP3 | iTunes

Those that come across this blog know that the mission is to give visibility to the expertise of the folks around Emerson Process Management. This post will be slightly different. It does feature an expert, Emerson's Jim Walker. He is a member of the Machinery Health Management business. As part of the Asset Optimization organization, this business is responsible for the CSI Technologies family of machinery health products.

Jim was primary inventor of the CSI 9420 WirelessHART vibration transmitter. This device provides vibration and temperature measurements, diagnostics, and alerts for plant machinery over a self-organizing wireless network for use by operations and maintenance personnel. I know from my days as an offshore oil & gas systems engineer back in the '80s, that adding vibration monitoring after the fact could be a difficult proposition, due to the wiring considerations. I could have used his invention back then!

I did indicate that this would be slightly different. Jim shared with me his spare time interests--film making and still photography. He displays the video portion of these talents perfectly in this video he describes:

...I put together for Emerson's Machinery Health Management business in Knoxville, TN. It follows the progression of construction of the Emerson sponsored Habitat for Humanity house built in April 2009.

Emerson Sponsored Habitat for Humanity House from Jim Walker on Vimeo.

After watching the video (with his suggested, "Turn up your speakers" method), I was inspired by the participation of all the Emerson people in this project and what they accomplished. You'll see them in a montage, starting at 4:25 of this 5:33 production.

Jim, thank you for sharing this with me and I hope it inspires more participation in these kinds of community service activities among Emerson businesses, and with other folks who come upon this post.

MP3 | iTunes

As I mentioned in an earlier "itchy publish button" post, it's always dangerous to include a blogger on your email distributions for upcoming items. I saw an advanced copy of a 2009 American Control Conference paper prepared by Rose-Hulman Institute of Technology's Atanas Serbezov and Ronald Artigue and Emerson local business partner, Cornerstone Control's Ron Knecht. The abstract for this paper, Bridging the Gap between Academia and Industry is:

This presentation describes the deployment of an industrial Process Automation System (PAS), in the Chemical Engineering Unit Operations (UO) laboratory at Rose-Hulman Institute of Technology and its incorporation in the undergraduate curriculum. The UO laboratory has over a dozen of pilot-scale process units (skids) and creates an environment very similar to a typical chemical, petrochemical or pharmaceutical plant. Students learn how to maintain their process under control, take it safely from one operating condition to another, collect and analyze data using a process historian, respond to process alarms and remotely troubleshoot their experiments with limited process information.

Rose Hulman's Chemical Engineering department's UO lab is 6500 square feet, includes process operations such as heat exchangers, pumps, a distillation column, chemical reactors filtration units, and a fermentor. The DeltaV system on which the students learn process control is physically separated from the campus local area network. The students do have remote access to the engineering stations and operator stations and wireless access within the Chemical Engineering building.

The units are outfitted with various measurement technologies. For example, flow is measured with Coriolis, vortex shedding, and orifice/differential pressure technology. Level is measured with ultrasonic and differential pressure instruments.

Three upper division courses are available which teach process control through experiment, data analysis, report writing, and oral presentations. Here's an example of one of the experiments described in the paper:

...in the tubular reactor experiment, the control system can maintain the flow rate through the reactor at set point very well, but the process will become unstable if a set point change from laminar to turbulent regime is executed in automatic mode. In this situation students have to switch from automatic to manual mode and move the system manually towards the new operating conditions.

The paper describes the professors' work with the collaboration of many industrial partners, including Cornerstone Controls and Emerson. In addition to equipment, they received technical advice from the control system architecture to the design of experiments and its associated documentation. Additional work is being looked at to bring virtual plant capabilities into the curriculum.

I was very impressed with the paper and what's being done at Rose-Hulman Institute of Technology to prepare the next generation of process control and automation engineers. The paper will be presented June 10-12, 2009 in St. Louis, Missouri, USA.

Storms blew through Austin the week before last knocking out power to our building. It reminded me of the criticality of reliable power to conduct business in this information age. If you're responsible for maintaining the power distribution facility at your plant, you know how critical it is to avoid unplanned power outages.

I caught up with Emerson's Cliff Kirby, a manager in the Electrical Reliability Services business. Cliff described some advances to their partial discharge (PD) testing and monitoring services that have expanded to include switchgear.

Now, for those not steeped in an electrical engineering background, partial discharges are small electrical sparks that occur within a cable's insulation, or on the surface of the insulation of medium and high voltage electrical equipment. These sparks result in the electrical breakdown of a small portion of the insulation surface or in an air pocket within the insulation. Over time, these partial discharges will erode the insulation and can result in a complete breakdown.

According to the National Fire Protection Association (NFPA 70B), the leading cause of electrical failures is insulation breakdown. The National Electrical Code (NEC) states that these partial discharges are the first indication of insulation deterioration. Research from the Recommended Practice for the Design of Reliable Industrial & Commercial Power Systems (IEEE Gold Book), Table 36, indicates that cables, switchgear, and transformers suffer the greatest losses from insulation failure.

Cliff indicated that it's impractical for most process manufacturers to de-energize their power system to perform testing. He noted that partial discharge testing and monitoring service could be performed online (while the electrical equipment is energized.) There are a lot of factors to consider in performing partial discharge testing including whether it's practical to de-energize the system, the age of your electrical assets, the material composition of the insulation, weather conditions, etc. Online testing can range from the use of a simple handheld detection unit, to periodic testing with special capacitive or high-frequency current transformers (HFCT) sensors, to continuous monitoring for the most critical or hard-to-access electrical assets.

As implied by the term "offline," this type of partial discharge testing can only be performed when the system is de-energized-such as when the installation is new and has not been released to operation or during a plant turnaround.

In the United States, more than ten industry standards provide information about field-testing medium voltage cables and components. The IEEE 400-2001 standard defines six tests and their advantages and disadvantages. One of the well-established tests, DC Hipot testing, may cause damage and premature failure in certain types of cables including EPR and XLPE cables.

In addition to online and offline PD testing, Cliff listed some other tests that the electrical reliability team performs: Ultrasonics, Tan Delta (dissipation factor testing), and Very Low Frequency (VLF) testing. Every plant has unique circumstances and selecting the right mix of test methods and technologies helps provide the diagnostic information necessary to analyze the data to spot problems well before an unplanned shutdown occurs.

These tests are usually incorporated into an ongoing program to help improve the maintenance plan and length of service of the electrical assets.

MP3 | iTunes

Update: I updated the links above for the Electrical Reliability and Partial Discharge links to the new Emerson website location.

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.

MP3 | iTunes

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.

MP3 | iTunes

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.

My spy utility, WatchThatPage, alerted me to another good article, this time on the Fisher control valves and regulators area of the Emerson website. The article, Getting ready for the nuclear renaissance, from the April issue of Valve World magazine, features Bill Fitzgerald, director of the Fisher Valves nuclear business unit.

As more and more people around the world climb the economic ladder, the global demand for energy continues to grow. A nuclear power renaissance is underway, according to Bill driven by:

...issues like global warming and a desire for energy independence... It can never be the only solution, but it is a logical part of the solution.

Bill describes his team tracking forty U.S. projects. He estimates two-thirds of these will actually be built. The first ones may come on-line as soon as 2015. Bill describes the large engineering firms as well as the U.S. Nuclear Regulatory Commission (NRC) staffing up anticipating the work required to completely design, build and commission the first wave of these plants over the next seven years. This expected growth is by no means limited to the U.S.

As part of this process, the engineering firms' procurement people need to identify and begin to purchase the long-lead items like reactor vessels, which may take three years from order to delivery. Control valves also fall into this long-lead item category. As Bill explains:

...control valves have long lead times because the ASME has just issued new qualification requirements. So to use a valve in a given safety related application will probably require 18 months of qualification testing. We also have to factor in ever-tighter seismic requirements. Then materials procurement, machining, assembly and testing will probably take an additional 9-18 months, depending on valve type. So, we believe that if we get an order today for a nuclear grade valve it could take as long as three years to actually deliver it to the end user.

And Bill notes that these valves are used in safety critical areas. Not having them will delay the startup of the plant. Based upon this expected global increase in nuclear power plants, Emerson and other automation suppliers are increasing their capabilities to meet this demand.

Technology has changed greatly since these types of plants were built in the U.S. a generation ago. Bill describes digital technologies like Foundation fieldbus, which can be used in the balance of plant applications to provide better control and diagnostic information. Devices like digital valve controllers have completed Electric Power Research Institute (EPRI)-certification for use in this demanding application.

As energy producers seek ways to meet the increasing global energy demand, these preparatory activities are critical to meet challenging project schedules.

Update: I was just pointed to a great Béla Lipták article, The Third Industrial Revolution by a member of our DeltaV Twitter community. Béla describes the post fossil fuel world based on solar power and the role of process automation. It's well worth your read and I look forward to his book due out in August.

I use a service, WatchThatPage, to track changes to various pages around Emerson Process Management. It sends me an email when any page in a list of pages I have created has changed. I use this as one of my sources for the posts I create. This helps me keep track of changes in non-RSS enabled pages. For those who don't use RSS (really simple syndication), here's some resources on how it makes your information quest more efficient.

Late last week I received an email notifying me of a change to the Daniel liquid pipeline surge relief technical guide. I caught up with Dave Seiler to ask about this application and some of the challenges process manufacturers with high-pressure pipelines face. Pipeline operators and those with high-pressure pipelines are quite aware of the potential damage that can occur if a pressure surge occurs.

Dave noted that over-pressurization of a pipeline is commonly caused by sudden changes in liquid velocity. This may occur when a pump starts or stops or a valve opens or closes. When a pressure rise occurs above normal operating pressure, it's very important to analyze the rate of the pressure rise to determine the proper size and type of valve required.

Dave described line blockage as the most serious pipeline issue. To mitigate this condition, pipeline design includes valve interlocking logic and clear operating procedures. As noted in the technical guide:

...pressure is contained must have some form of pressure relief, which is often mandated and regulated by local authorities. The design of such systems is dependent on a complex range of factors including, but not limited to, the potential for pressure increases, the volumes which must be passed by the pressure relief equipment in operation and the capacity of the system to contain pressures.

This guide describes applications you may have in your facility. On application is a pilot operated pressure relief valve used for pump protection duty and for similar applications where pressure relief is required to maintain pressure at a given set point. Another application might have exceptionally fast response times that require gas-loaded systems. These are described:

The basic valve is the balanced piston design. Nitrogen gas is used to pressurize the valve piston to keep it in the closed position. The valve incorporates an integral oil reservoir mounted on the external surface of the cylinder head, which upon installation is partially filled with a light oil. Gas under pressure is applied to the reservoir.

Other applications described include surge relief valve closed position and open position. I found the pictures like this one help make the text easily understandable.

If you have high-pressure pipelines in your process, take a look at this guide and see how it might help you.

High energy costs continue to prompt process manufacturers to seek ways to increase their energy efficiency. A colleague pointed a great post to me, The Seven Steps to Successful Industrial Energy Management, on the Energy Pathfinder blog.

My take away was that the culture for becoming more energy efficient starts at the top and developing metrics, incentives, and disincentives to change organizational behavior are keys to success.

I thought I'd share this post with Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization. You may recall Bob from earlier posts.

Bob believes improving the operation of the Industrial Powerhouse can be a large factor in improving overall energy management at process manufacturing sites. The carbon footprint of the powerhouse can be reduced, the reliability and responsiveness of the operation can be increased, and the cost of energy can be reduced--all at the same time.

With this focus (and not to be out done by the seven steps), Bob offers his ten steps to successful Industrial Powerhouse improvement:

1. Obtain top management commitment to improving the carbon footprint, reliability, and cost of operation of the Powerhouse.
2. Benchmark current operations in terms of efficiency, reliability, cost, and emissions.
3. Survey current process equipment, control technology, and operating methods. Create a matrix of factors that are impacting or limiting operating performance.
4. Examine potential process equipment repairs and upgrades that could deliver benefit, rank these in terms of return for investment, and complete repairs and upgrades that will deliver good immediate benefit.
5. Focus on process parameter measurement devices and actuators. Especially for combustion air and fuel flows, ensure that repeatable measurement and control capability exists.
6. Implement full automatic control that is robust and reliable. Even the best operating crews cannot optimize Powerhouse performance every minute of the day for every day of the year.
7. Install optimized control functionality as appropriate to optimize efficiency, prioritize lowest cost fuels, load equipment based on cost, and make economic operating decisions automatically.
8. Change Standard Operating Procedures for the Powerhouse to ensure that process units are run in automatic using the optimized control functions. Make focus of operations identifying and troubleshooting process issues rather than manual process operating adjustments.
9. Regularly benchmark operation in terms of efficiency, reliability, cost, and emissions, repeat steps above when results are not satisfactory.
10. Investigate and consider re-powering the industrial site with lower cost fuels and/or technologies.

Bob and the Industrial Energy Solutions consultants have helped process manufacturers achieve ongoing savings from improved energy efficiency by putting these steps into practice. If your energy costs are higher than they could be, give these ten steps a try or contact the industrial energy team for help.

In spite of my best efforts to use persistent RSS search feeds in order not to miss any news about Emerson experts in action, here's one that got by me.

Mark Coughran, a consultant on Emerson's Advanced Applied Technology team, shared this control challenge question he answered with me. You may recall Mark from earlier posts.

The question he addressed appeared on the ChemicalProcess.com's Ask The Experts website. The question, Control pressure at discharge, was:

I have five pumps running parallel, transferring water. Due to pressure fluctuation at discharge, which depends on the flow requirements of the user, I am planning to install a pressure control valve at the pump discharge to keep the pump running at an optimum condition... What kind of valve is best for a 14-in discharge?

Mark notes that he's seen problems with butterfly valves used on large water lines, but that things have improved with better valve, actuator, positioner, and application software. Common sources of problems include wrong valve size, shape of butterfly disk, backlash in disk-to-shaft and shaft-to-actuator connections, poor valve positioner performance, and insufficient torque.

Control valve suppliers have addressed these issues in a number of ways. Examples include better valve sizing software, improved butterfly valve disk shapes, zero-backlash connections, valve positioners responding to 0.1% signal changes, and sizing software that predicts installed torque.

Mark points out that globe valves are typically too expensive for this application. Butterfly or segmented ball valves may be better suited if the supplier's test data for the valve + actuator + positioner shows suitability in similar applications.

Mark's final guidance concerns the control strategy. He recommends a controller tuning method that does not oscillate, but responds at the application's required speed, such as Lambda tuning. He advises:

If you need to control the five lines separately, there will be interaction and balancing concerns. The options range from individual PID controllers to a multivariable controller. All the options are easy to configure and tune in a modern DCS.

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!

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.

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.

A leading research organization, the Aberdeen Group, says it well when they say:

In asset intensive industries, such as automotive, metals, mining, oil and gas, process manufacturing, utilities, and the public sector, the reliability and productivity of capital assets is essential to an organization's financial success. Maintenance of these assets can dramatically impact the overall performance and useful life of an asset.

Petrochemical manufacturers definitely consider themselves in this "asset intensive" group. As such, solid maintenance programs are essential. And it is especially critical to plan the times when they are shut down for maintenance. Known in industry parlance as a turnaround, these may happen only every 4-6 years. This means they frequently involve new personnel as people move on to new roles.

A Houston, Texas-based petrochemical manufacturer saw an Emerson Exchange presentation given by Emerson's Instrument & Valve Services (IVS) consultant Wade Enns. He described a Northern Alberta Oil Sands production project with 120,000 I/O to commission. A key to the success of this project was the use of the Smart Start project services methodology. It helped bring a well thought out plan and order to this huge commissioning task.

This methodology and associated software provides embedded check sheets and commissioning procedures for 196 specific equipment types, customized check sheets for planning and checking off tasks during the turnaround as they are completed. The process also helps prioritize the maintenance activities and documents them to provide an audit trail, should the refiner need to refer back to the maintenance activities performance.

The petrochemical manufacturer shared how they had real problems with their last turnaround with scheduling and quality of the work performed. Obviously, any delays impacting the start-up schedule mean lost revenue.

The IVS team worked with the manufacturer to plan the maintenance turnaround on the process with 600 loops and 1800 devices. The process began by building a Smart Start Project Tool database to capture the entire scope of the instruments and valves which were in use. The team took advantage of the plants installed AMS Device Manager. Next, to fully understand and document how everything was installed, they performed "loop walk-downs". This helped put together the plan for the priority and order of the maintenance to be performed.

Working collaboratively, the maintenance and IVS team fully documented and received signoff on the plan in time for the turnaround. With milestones in place, the team could catch deviations from the plan early so that additional resources could help in these areas.

The results were what this manufacturer wanted--a smooth turnaround executed in the allotted time. Given the pressures on everyone to get the maintenance work done in the allotted schedule, having this well thought out and documented plan definitely helped reduce the stress along the way.

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..."

You know you need to periodically get your car's oil changed and the lube oil system checked if you want the engine to last over the life you own your car.

It's the same for many process manufacturers who have large, critical turbomachinery assets. These can include air and gas compressors, steam turbines, power recovery turbines, power generating equipment, etc.

Like the oil required for your car engine, lube oil skids maintain oil flow to the bearings, seals, and servo-controls on these critical turbomachinery assets. The lube oil skids must react very quickly in the event of an oil pump trip or other disturbance condition.

I spoke with Mark Coughran, an Emerson Control Performance consultant who was involved in a recent plant turnaround at a Texas Gulf coast petrochemical manufacturer.

Mark said the challenge with the lube oil skids is to maintain the oil pressure in these disturbance conditions, since the compressor or turbine will trip and the plant will lose production during the often lengthy restart procedure.

For this petrochemical manufacturer, Mark used his expertise acquired over the years of working with these skids along with Emerson's Entech Toolkit to find the fastest stable tuning of the pressure controllers.

In this particular case, Mark estimates the cost in lost production from a single turbomachine trip dwarfs the cost of his applied expertise.

Emerson also has online Machinery Health Monitoring to predict conditions which may cause a trip and alert operators in time to avoid a trip. I'll have more on some of the experts who help manufacturers get the most out of this monitoring in a future post.