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Forget preventive maintenance. Today's uptime requirements call for an entirely different approach
For devices that do not have embedded diagnostics, users can install the necessary sensors on vital assets. It's not something you would want to do on thousands of devices in a typical plant, but condition sensors can be installed on assets of particular interest. If a certain pump, valve, compressor, or similar device is failing and causing problems, it could be fitted with vibration or voltage sensors on a permanent or temporary basis until the problem is diagnosed. For example, Allen-Bradley's MachineAlert relays can be installed in a control panel to monitor phase, current, temperature, and motor rotation in any motor control application.
It's also possible to make manual vibration measurements on certain key machines. For example, SKF's MicroVibe portable vibration test and measurement instrument can be used with a PDA; this lets a technician run out into the plant periodically to check critical systems. The Ultraprobe 1000 from UE Systems has its own on-board recording, logging, and application software for ultrasonic condition analysis locally or later at a computer.
When buying new or replacement equipment, it's a good idea to seek out devices that have built-in sensors and embedded diagnostics.
"Investing in assets that can communicate when they require attention, such as maintenance or calibration, is critical to proactive strategies," says Mark Bitto, product manager of asset optimization products at ABB, Wickliffe, Ohio. "Intelligent field devices, control systems, workstations, and network hardware all contain a rich set of embedded diagnostic information. Unfortunately, unless the device is enabled to report these health conditions, the information will go unnoticed for long periods of time."
This means all that condition sensing and diagnostic data needs to be acquired for further analysis.
Plucking Data by PDA
At one end of the data acquisition cost spectrum, PDAs are rapidly replacing notebooks and clipboards in the maintenance arsenal. PG&E technicians, for example, use them to record daily readings and make on-the-spot checks of equipment.
Steacy says software in PG&E's PDAs can check the current reading to see if it is within limits for each device. "If the operator makes an entry the system deems out of range, DST's dBehold software will alarm and prompt for data re-entry," he explains. "This prompts the technician to make a visual inspection of the meter to determine if it was a transcription error or if the meter is having a problem. If an equipment fault is discovered, the tech can flag it for maintenance." Maintenance departments everywhere are using similar handheld PDAs and laptop computers.
Many maintenance departments realize the benefits of automated maintenance technology, but simply can't afford it, so they stick with their manual systems.
"We are looking at replacing any failed transmitters and new installs with fieldbus transmitters, mainly because of wiring and future advances in information provided," says Matt Smith, process control supervisor, Amalgamated Sugar Co., Twin Falls, Idaho. "We looked at Emerson's AMS, but couldn't justify the per-point costs because we have about 2,500 transmitters and 1,000 control elements. We employ 10 instrumentation technicians and are currently implementing an electronic work-order maintenance management system. I guess the bottom line is, we have the labor to do it manually."
When we asked end users for inputs on how they were acquiring data for maintenance purposes, several agreed with Smith, telling us they simply could not afford to install fieldbus instrumentation and asset management software.
Few are as lucky as James Loar, engineering group leader at Ciba Specialty Chemicals, Newport, Del. "We are in the process of installing a system to monitor reliability of process control and instrumentation," he told us. "We are installing a system with Foundation fieldbus, DeviceNet, Profibus, and AS-i. A new corporate standard for control systems forced us into the luxury of having this capability."
Fieldbus, DAQ and Asset Management
Clearly, the dream solution for an RCM system is fieldbus instrumentation connected to a distributed control system (DCS), an asset management software package, loop analyzer, performance analyzer, and a computerized maintenance management system (CMMS), all of which costs only slightly less than one of Saddam's gold-plated bathrooms.
"Predictive maintenance technologies that integrate with the process automation system offer distinct advantages to users," says Stuart Harris, vice president of Emerson Process Management's Asset Optimization Div. (www.emersonprocess.com). "We see a clear trend toward operators playing a first-line role in reliability and maintenance. Therefore, the ability to send predictive equipment advisories to operators is very valuable. Emerson accomplishes this goal in its PlantWeb digital plant architecture, which combines process automation with asset management."
All the major process control vendors have their own asset management/CMMS software, or they form alliances. Honeywell integrated Asset Manager PKS and its Loop Scout directly into its asset management system, Experion PKS. Invensys combined its Archestra framework architecture with its Wonderware HMI/SCADA software and Avantis asset management software. ABB has allied with Accenture, and Integraph uses AM software from Meridium. Suffice to say, if you have a process control system from a major vendor, you can get everything you need to do RCM.
Much less expensive solutions are readily available. For example, at National Manufacturing Week, we saw a number of vendors--HMW, InduSoft, Applied Data Systems, Advantech, H-P, and Siemens--combine their products into a data acquisition system just by plugging them together via Ethernet and .Net, and writing a little software. It took two weeks to set it up, said the InduSoft programmer who put it all together.
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