Assigning maintenance responsibility to an outside contractor might make economic sense in some cases, but that group must have access to essential information about plant equipment and systems, or they’re in trouble. When long-term employees with corporate knowledge are no longer around to tell why a pump cavitates under certain conditions or warn that some sensor lines plug frequently, the new technicians do a lot of wheel-spinning while trying to troubleshoot unusual events.
After the maintenance department at the Galata Chemicals plant in Taft, Louisiana, was downsized as a part of cost-reduction moves in 2007, most records pertaining to the process control system fell into disarray. While the contract personnel were well-qualified, they couldn’t find much of the information they needed to do their jobs. Technical documentation was almost nonexistent, control-loop piping and instrumentation diagrams (P&IDs) couldn’t be found, and there was no way to determine how many field devices were in use or how many spares were available. In some cases, dual records existed, but they weren’t identical. Just finding documentation on field devices was time-consuming.
Another cost factor was the excessive time spent reacting to emergencies, the most expensive kind of maintenance. The new group was reduced to fighting one fire after another just to keep the plant running, and routine maintenance was neglected. A great deal of time wes spent locating instruments with no drawings for guidance, and once a device was identified, basic procedures were almost impossible to implement without manuals or spec sheets. As a result, the cost of the contract service turned out to be much higher than anticipated.
Asset management revitalized
Two actions were taken almost simultaneously. I was hired in June 2008 as a control systems specialist with authority over instrument calibration and maintenance. In addition, the company brought in a systems consultant from Emerson Process Management (www.emersonprocess.com), our control system supplier. His assignment was to help with instrumentation questions, but he was soon asked to restore the existing asset management software.
Our first task was reconstructing the instrument database in the AMS Suite: Intelligent Device Manager asset management software. This system was initially implemented in 1998, primarily to support instrument calibration by maintaining specification sheets, P&IDs and calibration records. The instruments were entered into the database initially as conventional devices, meaning that information the plant’s HART-based smart devices generated wasn’t being used for maintenance purposes. Later, the HART-enabled devices were turned on, making field-generated diagnostics available, but different device tags were assigned for this purpose. The numbers never were linked, causing confusion among the contract technicians.
Using the general application launcher, which is part of AMS Device Manager, we identified the HART-enabled devices and separated them from the conventional instruments. We were then able to link the loop sheets, specification sheets, P&IDs and maintenance manuals along with approved calibration procedures with the database. Finally, we eliminated the duplications, and the resulting field instrumentation system had some structure.
Now, every one of the 1,650 instruments in the plant, including some 400 digital valve controllers (DVCs), has a unique tag number. Anyone with a basic knowledge of the software can find any information needed to troubleshoot suspected field device problems. We can determine the operating condition of any device and much of the associated process equipment and we can predict when an asset should be taken out of service for repair/replacement.
Using the principles of predictive maintenance, the contract workers now are able to provide the level of maintenance needed to prevent the unexpected “fires” that occupied them in the past.
AMS Device Manager monitors the smart devices continuously and raises alarms if any preset operating limits are exceeded. While every alarm requires immediate attention, they can indicate trouble brewing and we monitor them daily. I can retrieve diagnostic information from any device that appears to be performing below expectations. If necessary, an I&E technician can check the device and the equipment it monitors. Any of these steps can trigger predictive maintenance if conditions call for it.
In quite a few cases, instruments or process equipment problems have been discovered before the control system operators knew they existed. Catching a potential problem before it occurs avoids a great deal of troubleshooting and eliminates downtime.
Most importantly, calibrations are being completed on schedule following Emerson’s written calibration procedures. When it’s time for a group of instruments to be calibrated, specific variables are downloaded to documenting calibrators technicians use on pre-planned calibration routes. The results of each calibration are uploaded to the database, becoming part of each instrument’s historical file. We now have accurate, up-to-date calibration records that satisfy our corporate requirements as well as those of state regulatory agencies. In this way, we avoid potential environmental problems.
We’re now taking care of nearly 2,000 field devices with about half as many workers as before — just one instrument tech, an apprentice and two electricians. Process control is improved and more consistent, and this is reflected in better equipment reliability, higher product quality and greater productivity.
On a personal note, I’m getting more sleep. At one time, I was spending 70 hours to 90 hours at the plant each week, sometimes in the middle of the night. I now work a fairly normal 40 hours schedule, and everything is fine at home.