When you have to hop on a helicopter to investigate instrument failures and make repairs, remote diagnostics becomes more than just a matter of convenience. It’s also a matter of money. Without diagnostics, your bottom line can take huge hits when equipment fails without warning and your maintenance technicians have to fly out to one of your natural gas platforms in the English Channel or North Sea. Because reducing these expenses was important to GDF Suez A.B., the Paris-based energy company invested in digital fieldbus technology. Intelligent sensors on the network now warn the operations staff early about developing problems, so technicians can take corrective action before they have a chance to degenerate into outright failures. Even better, the inherent diagnostics can often provide technicians with enough warning to make the repairs during a scheduled stop to the platform.GDF Suez opened this window into its operations when it upgraded its old network of pneumatic controls and discrete wiring to a new one based on Foundation Fieldbus from Phoenix-based Honeywell Process Solutions. “The Foundation Fieldbus system integrates with Honeywell transmitters, as well as other, third-party transmitters,” says Hans Katers, GDF’s head of mining installation.The resulting digital network established serial, two-way communications with the company’s offshore platforms, thereby allowing both remote control and monitoring. Now, the operations staff has access to more information that can tell it whether feedback devices are operating correctly and whether the process information that they are transmitting is good or bad. Not only are technicians spending less time verifying whether the devices are working, but they no longer need to perform many of the routine checks that they did before.The ability to track trends also gives them prognostics. “The ability to predict [performance] also helps increase platform uptime and performance by detecting or predicting deteriorating performance and failure conditions before they cause any problems,” notes Hans Kwee, one of GDF’s instrumentation engineers.This combination of diagnostics for assessing the health of an asset and the prognostics for maintaining it proactively constitute the true benefit of fieldbuses and intelligent transmitters, according to John Yingst, Honeywell’s product manager for asset management. “The value of fieldbuses is not in the wiring savings and other promises that were touted early on in their life cycle,” he says.Easing the burden
Another advantage of fieldbus-based diagnostics is that it can supplement the Ethernet-based embedded signal processing that many in the oil-and-gas industry are putting into their machinery that requires high-speed data acquisition and feedback. Although an intelligent sensor might be adequate for some control loops in the process industry, an additional level of data acquisition and signal processing is often necessary for compressors, pumps and other high-speed, heavy machinery that are driving those processes.“You can imagine how fast streaming raw data back to the control room would fill up the hard drives,” says Preston Johnson, segment manager for sound and vibration sales and marketing at National Instruments Corp. (NI) an Austin, Texas, automation supplier. “Processing that information to reduce it to a smaller set of much more meaningful information makes the application a lot easier.” His company does this with the latest analog-to-digital converters, field-programmable gate arrays, and microprocessors that can perform fast Fourier transform analyses on the data.Because of the processing speed, Supreme Electrical Services Inc., a Houston-based supplier of controls and instrumentation for the oil patch, has been using NI’s CompactRIO Ethernet-based products in its high-pressure fracturing pumps. “Other hardware we considered was not able to provide the high-speed I/O (input/output) and analysis to catch the momentary pressure spikes and vibration indications of these oil-well service pumps,” says Robert Stewart, senior vice president at Supreme Electrical. Both the high-power diesel engine and the transmission on these triplex or quintaplex pumps have an electronic interface that monitors discharge pressure, rotational speed and other operating parameters. The interface provides diagnostics while the pump is running and transmits the data to the main control console via the SAE J1939 controller area network (CAN) communications protocol. “With this real-time information, operators can determine whether they should continue or discontinue operations based on real performance indications from the pump,” says Stewart. For more on Fieldbus Technology, see"Fewer Fieldbus Programming Headaches".Perhaps the biggest challenge confronting companies such as Supreme Electric for integrating diagnostics into their machinery is not so much collecting data in real-time, but rather developing the software for interpreting their significance. “A facility can use OPC (an open connectivity standard) to bring together process data from smart transmitters and vibration data from off-the-shelf software to make better decisions,” notes Johnson at National Instruments. “But there still needs to be a bit of work on the part of an expert who really understands how the process and equipment are working together.”He offers the example of his company’s vibration monitoring systems, which capture vibration data and do some initial signal processing to identify, for example, bearings that are vibrating a little more than usual, or a shaft that has gone a little out of balance. “That’s not a complete picture, though,” he says. “You need to pull together all the information from the different sources and look at what it says about how well the entire process is operating.” He points to research at the University of Cincinnati (Automation World, June 2007, p. 8) and elsewhere into aggregating large collections of data and developing automatic rules for determining how sensors and systems are working together.Meanwhile, equipment builders can use various kinds of programming aids to streamline the development of software that can put data into context for a particular machine or process. The engineering staff at Supreme Electrical is using National Instrument’s LabView graphical programming software to program the real-time processor, gate arrays, and I/O hardware that it uses to control and monitor its equipment. “It has made the software development side much quicker than our past experiences in C-based programming,” reports Stewart. “What most C programmers take two years to do, we can accomplish in a couple of months.”Ounce of prevention
Users are also tying their device diagnostics to another class of software called plant asset management (PAM) that the major controls suppliers offer. The goal of such software is to help users to move from a reactive maintenance strategy to a proactive or predictive one. The resulting savings can offset the additional cost of installing a digital bus rather than a more conventional 4-to-20 milliAmp (mA) analog system.“Industry studies have shown that 65 percent of maintenance trips to the field are unnecessary,” observes Bernd Schuessler, business development manager at automation vendor Pepperl+Fuchs Inc., in Twinsburg, Ohio. “With intelligent devices, the instruments report automatically when they need maintenance.” Users no longer need to perform routine maintenance at set intervals, whether the device needs it or not.Schuessler stresses the need to monitor the physical layer, in addition to the intelligent digital fieldbus instruments. “The digital bus physical layer represents the backbone of the entire bus structure,” he notes. “If it is not installed correctly, it can bring down an entire plant, because the information from the devices connected to it cannot be delivered to the control system and PAM.” For this reason, his company developed advanced physical layer diagnostics (ADM), a technology that bridges the gap that existed between instrument diagnostics and the control system.One of the tools built into ADM is a commissioning wizard. Schuessler reports that, when P+F installed Foundation Fieldbus at Eastman Chemical Co., in Columbia, S.C., this wizard cut the commissioning time by 80 percent, when compared to conventional procedures. Assisting the ADM in watching over the fieldbus network are P+F’s Foundation Fieldbus power conditioners and FieldBarriers.Besides deploying the commissioning wizard, Eastman also uses the ADM to monitor the physical layer of its Foundation Fieldbus and warn its operations staff of any deviations from the base line established at the commissioning. Now, technicians can identify potential problems in the physical layer—such as segment noise, jitter, ground faults, polarity checks, and missing terminator detection—before they can interrupt communications. When troubleshooting becomes necessary, the technicians use ADM’s other tools, such as the fieldbus oscilloscope, to pinpoint problems. “This helps them to reduce unwanted downtime and increase production,” says Schuessler.Another level of diagnostics support made possible in part by digital fieldbus is the asset-management services offered by automation vendors. Consider the experience of a Michigan-based power company that had difficulty bringing up a unit from a planned shutdown late one Friday evening. One of the modules that had been reset continued to report an error. “Something was wrong with the configuration somewhere,” reports John DuBay Jr., business development manager for remote services at vendor ABB Inc.’s Process Automation Division, in Wickliffe, Ohio.When the technician called ABB’s SupportLine, a service engineer returned his call within 30 minutes. He logged into the power company’s continuous monitoring system, diagnosed the problem and reloaded the module remotely. Not only did the remote diagnostics avoid costly delays, but the power company’s technician also got to go home that night and get a good night’s rest—the benefit of a good diagnosis.
Another advantage of fieldbus-based diagnostics is that it can supplement the Ethernet-based embedded signal processing that many in the oil-and-gas industry are putting into their machinery that requires high-speed data acquisition and feedback. Although an intelligent sensor might be adequate for some control loops in the process industry, an additional level of data acquisition and signal processing is often necessary for compressors, pumps and other high-speed, heavy machinery that are driving those processes.“You can imagine how fast streaming raw data back to the control room would fill up the hard drives,” says Preston Johnson, segment manager for sound and vibration sales and marketing at National Instruments Corp. (NI) an Austin, Texas, automation supplier. “Processing that information to reduce it to a smaller set of much more meaningful information makes the application a lot easier.” His company does this with the latest analog-to-digital converters, field-programmable gate arrays, and microprocessors that can perform fast Fourier transform analyses on the data.Because of the processing speed, Supreme Electrical Services Inc., a Houston-based supplier of controls and instrumentation for the oil patch, has been using NI’s CompactRIO Ethernet-based products in its high-pressure fracturing pumps. “Other hardware we considered was not able to provide the high-speed I/O (input/output) and analysis to catch the momentary pressure spikes and vibration indications of these oil-well service pumps,” says Robert Stewart, senior vice president at Supreme Electrical. Both the high-power diesel engine and the transmission on these triplex or quintaplex pumps have an electronic interface that monitors discharge pressure, rotational speed and other operating parameters. The interface provides diagnostics while the pump is running and transmits the data to the main control console via the SAE J1939 controller area network (CAN) communications protocol. “With this real-time information, operators can determine whether they should continue or discontinue operations based on real performance indications from the pump,” says Stewart. For more on Fieldbus Technology, see"Fewer Fieldbus Programming Headaches".Perhaps the biggest challenge confronting companies such as Supreme Electric for integrating diagnostics into their machinery is not so much collecting data in real-time, but rather developing the software for interpreting their significance. “A facility can use OPC (an open connectivity standard) to bring together process data from smart transmitters and vibration data from off-the-shelf software to make better decisions,” notes Johnson at National Instruments. “But there still needs to be a bit of work on the part of an expert who really understands how the process and equipment are working together.”He offers the example of his company’s vibration monitoring systems, which capture vibration data and do some initial signal processing to identify, for example, bearings that are vibrating a little more than usual, or a shaft that has gone a little out of balance. “That’s not a complete picture, though,” he says. “You need to pull together all the information from the different sources and look at what it says about how well the entire process is operating.” He points to research at the University of Cincinnati (Automation World, June 2007, p. 8) and elsewhere into aggregating large collections of data and developing automatic rules for determining how sensors and systems are working together.Meanwhile, equipment builders can use various kinds of programming aids to streamline the development of software that can put data into context for a particular machine or process. The engineering staff at Supreme Electrical is using National Instrument’s LabView graphical programming software to program the real-time processor, gate arrays, and I/O hardware that it uses to control and monitor its equipment. “It has made the software development side much quicker than our past experiences in C-based programming,” reports Stewart. “What most C programmers take two years to do, we can accomplish in a couple of months.”Ounce of prevention
Users are also tying their device diagnostics to another class of software called plant asset management (PAM) that the major controls suppliers offer. The goal of such software is to help users to move from a reactive maintenance strategy to a proactive or predictive one. The resulting savings can offset the additional cost of installing a digital bus rather than a more conventional 4-to-20 milliAmp (mA) analog system.“Industry studies have shown that 65 percent of maintenance trips to the field are unnecessary,” observes Bernd Schuessler, business development manager at automation vendor Pepperl+Fuchs Inc., in Twinsburg, Ohio. “With intelligent devices, the instruments report automatically when they need maintenance.” Users no longer need to perform routine maintenance at set intervals, whether the device needs it or not.Schuessler stresses the need to monitor the physical layer, in addition to the intelligent digital fieldbus instruments. “The digital bus physical layer represents the backbone of the entire bus structure,” he notes. “If it is not installed correctly, it can bring down an entire plant, because the information from the devices connected to it cannot be delivered to the control system and PAM.” For this reason, his company developed advanced physical layer diagnostics (ADM), a technology that bridges the gap that existed between instrument diagnostics and the control system.One of the tools built into ADM is a commissioning wizard. Schuessler reports that, when P+F installed Foundation Fieldbus at Eastman Chemical Co., in Columbia, S.C., this wizard cut the commissioning time by 80 percent, when compared to conventional procedures. Assisting the ADM in watching over the fieldbus network are P+F’s Foundation Fieldbus power conditioners and FieldBarriers.Besides deploying the commissioning wizard, Eastman also uses the ADM to monitor the physical layer of its Foundation Fieldbus and warn its operations staff of any deviations from the base line established at the commissioning. Now, technicians can identify potential problems in the physical layer—such as segment noise, jitter, ground faults, polarity checks, and missing terminator detection—before they can interrupt communications. When troubleshooting becomes necessary, the technicians use ADM’s other tools, such as the fieldbus oscilloscope, to pinpoint problems. “This helps them to reduce unwanted downtime and increase production,” says Schuessler.Another level of diagnostics support made possible in part by digital fieldbus is the asset-management services offered by automation vendors. Consider the experience of a Michigan-based power company that had difficulty bringing up a unit from a planned shutdown late one Friday evening. One of the modules that had been reset continued to report an error. “Something was wrong with the configuration somewhere,” reports John DuBay Jr., business development manager for remote services at vendor ABB Inc.’s Process Automation Division, in Wickliffe, Ohio.When the technician called ABB’s SupportLine, a service engineer returned his call within 30 minutes. He logged into the power company’s continuous monitoring system, diagnosed the problem and reloaded the module remotely. Not only did the remote diagnostics avoid costly delays, but the power company’s technician also got to go home that night and get a good night’s rest—the benefit of a good diagnosis.
