Here are seven prescriptions to help you keep process equipment in optimal condition. Generally, proper maintenance is crucial; however, sometimes the best approach is "laissez-faire." A plant's production performance largely depends on the condition of its process instrumentation, which includes sensors and transmitters for parameters such as flow, level, pressure, and temperature, as well as analyzers and control valves. What can we do to keep field instruments healthy and operational without consuming additional resources? Here, field experts offer several possible measures and discuss the advantages and disadvantages of EDDL and FDT/DTM for describing valve parameters. Prescription #1: Correct Selection The first step in proper process instrumentation maintenance is correct selection. "Correct" here means "suitable for the actual application." For example, a complex smart instrument is unnecessary for low-priority tasks. However, for critical process applications, smart instruments with FOUNDATION fieldbus, Profibus, or HART communication should be selected. Tom Wallace, Global Marketing Manager at PlantWeb Emerson Process Management, says that choosing the right instrument type is crucial in applications requiring high control precision. The reason is simple: in traditional 4-20mA signal systems, the transmitter section invariably includes a digital-to-analog converter (DAC), and the control system section invariably includes an analog-to-digital converter (ADC). Both of these devices introduce bias and drift. He adds that, in addition, digital transmitters can provide and transmit a large amount of information. Secondly, using isolated transmitters is important. Although most DCS and PLC inputs are isolated, certain devices and other noise sources often introduce significant electrical noise into the system, causing errors. Using isolated transmitters helps minimize such noise interference. Furthermore, we recommend against over-reliance on pressure, temperature, and level switches for individual parameter control, as their malfunctions are difficult to detect promptly. A more reasonable configuration would be to use switch signals as backup for continuous analog signals, as the continuous output of analog signals can be easily monitored. Prescription #2: Proper Equipment Installation Even the world's best instruments will fail to perform properly and may even be permanently damaged if not installed correctly. Therefore, pay close attention to the following points during installation: ■ Equipment Location. For example, do not install a pressure transmitter on top of a steam pipe or a continuously draining condenser, as the sensor will be exposed to flowing steam 100% of the time. ■ Piping Arrangement. Ensure there is a sufficiently long straight pipe section upstream of the flow meter, or that a flow regulator is installed. ■ Installation. Install the instrument in the appropriate orientation: gas upwards, liquid downwards. ■ Wiring. Carefully plan the wiring for the pulse transmitter. Eliminate it if practically feasible. ■ Power Input. Ensure the instrument's power supply is reliable, free from electrical noise, surges, and spikes. ■ Grounding. Some instruments, such as direct-reading frequency meters, must be properly grounded. Ensure the shielding system is grounded at only one point. ■ Ambient Temperature. Operating sensors or transmitters outside their rated temperature range will significantly shorten their lifespan. ■ Corrosive Gases. According to Scott Saunders, Vice President of Marketing and Sales at Moore Industries-International, the following situation often occurs in the chemical industry: "When workers connect an RTD (Resistance Thermometer) to a transmitter, they often operate as follows: The maintenance personnel install the RTD in a new application, and everything seems to be working perfectly. Six months later, the maintenance personnel inspect the instrument according to the preventative maintenance plan. First, they remove the RTD's wires, then connect an RTD signal simulator, set it to a specific temperature range, and perform a joint test with the control room to ensure the signal checks the full range and that the readings are consistent at checkpoints of 4, 12, and 20 mA. Once the test is complete, the RTD and transmitter wiring is restored. However, the biggest measurement error is once again introduced into the entire measurement system: the three-wire RTD's wires have corroded." When using a three-wire RTD, the premise is that the wire impedance does not change. However, when the RTD is in a corrosive gas environment, the wire impedance increases over time. In this case, using a four-wire installation scheme will minimize the error caused by this problem. ■ Installation in Class I Div. 1 areas. Saunders said, “I was quite surprised to find that a large number of Class I Div. 1 instrument housings—explosion-proof housings—did not seal properly under their connecting threads. I even found that, during commissioning, calibration, and wiring of this class of instruments, although glass covers were installed, their connecting threads were not screwed all the way in and the gaskets were not tightened throughout. These threads were there for only one reason: to cool the gases before they came into contact with the air.” Once the instrument is installed, the first priority is to verify the proper setup and installation. We can use the device’s self-diagnostic tools to check for installation errors. If the instrument has a simulation mode, this function can also be used to check and ensure everything is working correctly, Wallace of Emerson added. Prescription #3: Let it run its course Once the instrument is installed and functioning properly, the best approach is to let it run its course until it issues a fault alarm. "High-end instruments are highly reliable and accurate, and once installed in the factory, they generally require no further calibration. You can directly use the instrument manufacturer's calibration data, and only need to perform a zero-point calibration once, after the instrument is installed in the correct orientation and the process medium has filled the pulse transmitter tube. The next time you need to perform a zero-point calibration might be ten years from now." Wallace also pointed out that unless the measuring range needs to be changed, repeated calibration of the instrument is often counterproductive. Everyone should learn how to consult the documentation provided by the instrument manufacturer. He added, "The calibration performed by the instrument manufacturer is often more effective than calibration performed by the user in their own factory or on-site." "[ALIGN=CENTER] As shown in the diagram provided by Emerson Process Management, ensure that there is either a sufficiently long straight pipe section upstream of the flow meter (a) or a flow regulator is installed (b). Figure 1 According to Emerson Process Management, as shown in the diagram above, the wiring of the pulse transmitter must be careful, and its length should be minimized if possible.[/ALIGN] Saunders of Moore Industries says that the above practical application solution works mainly for the following two reasons: "First, these devices are very reliable and not too expensive, so if a major failure is found, we can immediately replace it with a new one." "Secondly, digital instruments all have built-in self-diagnostic tools. If hardware or software malfunctions, they can issue timely alarms based on online status monitoring. Some maintenance personnel only reluctantly abandon their habit of regularly calibrating instruments. The best way to convince them that repeated instrument calibration is indeed unnecessary is to establish a database. A calibration instrument capable of data archiving would be helpful, but sometimes it is precisely such a database that can be misleading. Saunders says, 'Some people are often willing to invest in new technologies, such as FOUNDATION fieldbus or Profibus, but they don't build corresponding middleware, such as asset management optimization packages, to fully utilize digital data such as status bits, calibration, and drift.'" "[ALIGN=CENTER]Figure 2 suggests that for instruments used in Class I, Div. 1 explosion-proof areas, such as a field-installed transmitter for measuring the surface temperature of a natural gas pipeline, the housing screws must be tightened downwards and the gaskets pressed down to ensure the appropriate explosion-proof rating.[/ALIGN] This "set up, then forget" approach is not applicable to measurements in safety-critical applications where process equipment needs to be validated; similarly, it is not applicable to equipment used in harsh environments or that may be subject to contamination or abrasion. Analytical equipment and valves also fall into this category. Special maintenance is required if installed in corrosive, abrasive, severely vibrating, or extremely high-temperature environments. Furthermore, the above approach is not applicable to the maintenance of certain valves with moving parts whose characteristics change over time and with different applications. Prescription #4: Observe and listen to the signs" " One way to determine if an instrument is functioning correctly is to check for process noise. If an instrument's reading hasn't changed for several weeks, there are two possibilities: either the process is very stable, or the instrument is damaged. Wallace from Emerson stated, "I recall a time when a technician said during an analyzer installation, 'This pH meter has been stuck at 7.2 for 18 months.' It turned out the probe had been completely covered in dirt over those 18 months, preventing it from measuring the actual parameters. Sometimes, the presence of process noise in the signal actually indicates that the instrument is functioning normally and hasn't 'gone awful.'" "Some transmitters have built-in damping modules with damping coefficients of a few seconds, which can reduce process noise, and it is the noise signal that reflects whether the instrument is operating normally. However, if we are using FOUNDATION fieldbus or Profibus instruments, the instrument can display it as a digital signal even if the noise is not significant in the process variable signal. This function is very useful for tracking the standard deviation of process noise. Wallace said, "An increase in noise means several possibilities: air entrainment in the process steam, the presence of throttling flow, or the insertion of pulse lines, etc." "If the above situation occurs in the oil and gas sector, it reflects the possibility of sand in the fluid. Prescription #5: Focus on Secondary Variables Many modern instruments collect data on more than one variable, although not all are usually displayed. For example, many pressure and flow instruments also measure temperature—process temperature or the instrument's own temperature—and keep a record internally for future reference. Paul Schmeling, Pressure Products Marketing Manager at Emerson Process Management, says, 'Electronic components have their optimal operating temperature; for example, a platinum resistance thermometer (PRT) built into the circuit can determine if the temperature of a relevant electronic component has exceeded its rated range. ' Prescription #6: Carefully Handle Necessary Alarms An instrument, through proper settings, can record the range of pressure changes it has endured. Some abnormal conditions may shorten the instrument's lifespan or cause zero-point drift. We can set up signals on the instrument to notify the user of information such as: the instrument should be checked now; a heat tracing supply that should be turned off is still on, or vice versa." If we intend to monitor all possible data from the system's digital instruments, the biggest problem is the so-called "alarm flood." When the process is disturbed, alarm signals often emerge from numerous sources, and the unfortunate operators may be completely overwhelmed by this "alarm flood," unable to respond promptly and effectively to alarms that could lead to potentially disastrous consequences. Perhaps the most familiar example is the 1979 Three Mile Island nuclear power plant accident in the United States, which nearly resulted in a nuclear disaster. Similar accidents have occurred in the United States and other countries. The most effective way to prevent this is to incorporate all alarms into an alarm management system (for example, an industry standard requires only six alarms per hour). Current DCS systems have intelligent software tools that can assist in this function. Unless there is an emergency, it is best to ignore minor alarms that are unlikely to cause major problems. Charlie Piper, Fieldbus Product Manager at Invensys Foxboro, says, “Many devices have warning limits and alarm limits, and use classifications like high-limit alarms and super-high-limit alarms to indicate the urgency of the problem. Some devices may have as many as 20-30 warning or alarm limits, so the system can take these boundaries into account and trigger different action sequences depending on the specific situation.” Prescription #7: Turning Data into Information All data acquired from smart sensors or transmitters is of little use without correlation analysis. Saunders of Moore Industries says, “Many users install almost every data acquisition tool, but lack corresponding data processing and reporting processes, as well as software that provides predictive maintenance, which is essential for achieving ROI or proper instrument calibration. Asset management systems can save considerable maintenance costs because they generate useful information, promoting a shift from preventative to predictive maintenance.” Asset management systems are also helpful for valve positioners. Piper of Foxboro says, “You can track the number of times the positioner reverses. Typically, it can also be used to track and calculate the cumulative stroke of the valve stem.” “And you can also determine when certain components are deteriorating,” he explained. “Most valve positioners have numerous device parameters. For example, there’s ‘excessive deviation,’ which reflects increased resistance on the valve stem. In this case, the control command might be to open the valve to a certain degree, but it might not actually reach the desired position.” However, by observing the 20 or 30 relevant parameters provided by these devices, it’s possible to trigger a sequence of actions as needed to address these issues, he said. “If you can effectively utilize an asset management system and appropriate software,” Saunders added, “you can frequently test various indicators of valve characteristics, observe for component drift, or schedule predictive maintenance (PM) procedures.” He mentioned a user who, by calculating the frequency of a valve reaching its seat position, found that the frequency was not very high and that predictive maintenance was not yet necessary. Interestingly, this user made this judgment not based on an asset management system, but simply through a simple HART interface module that triggered a signal input to the DCS system whenever the valve stem position was less than 1%. Data collected and correlated by the asset management system could potentially provide a predictive maintenance strategy. However, in some situations, traditional preventative maintenance, or even fail-safe maintenance, might be a better choice. For example, for a large storage tank that takes a week to fill or empty, a failure of its level transmitter is not particularly urgent. "The wisest approach is often to do nothing." In short, if the latest technology is used, or the equipment is not a critical component, then the wisest approach is often to do nothing. Wallace said, "If a part of the instrument or terminal component is prone to wear or contamination, and its measurement parameters involve safety, environmental, or significant economic impacts, then preventative maintenance or predictive maintenance is necessary." In most cases, the concept of preventative or predictive maintenance needs to be shifted from "going out to do the work" to "real-time monitoring and automated diagnosis when necessary." In fact, one of the biggest causes of instrument failure is operating or repairing instruments indiscriminately without rigorous analysis. Therefore, if the potential consequences of an instrument failure are not too serious, the best approach is to leave it alone until it completely fails before replacing it. Regarding valve parameter description: whether EDDL or FDT/DTM is the best communication method between field devices and the control system is a matter of debate among manufacturers. Currently, the "fieldbus war" includes supporters of FOUNDATION Fieldbus, Profibus, and many other protocols vying for dominance. There is also no consensus on how to optimally handle configurable parameters in field devices and how to present them to users. On one hand, some manufacturers support Device Description Language (DDL), which has now evolved into Electronic Device Description Language (EDDL); on the other hand, some manufacturers prefer Field Device Tool/Device Type Management (FDT/DTM) technology. The earliest, older technology was the Device Description (DD) file developed by manufacturers, which included basic data for each device. The host computer would then retrieve this data and present it to the user. Martin Zielinski, director of HART and fieldbus technology at Emerson Process Management, said, "While field device manufacturers describe the relationships between parameters and how to group and display them, the exact format ultimately depends on the host computer." FDT/DTM technology is a standard environment designed for the maintenance and configuration of field devices. DTM is a technology for device maintenance and diagnostics, and it can be used as a plug-in in the host system's engineering and asset management system software. Unlike device description languages, the DTM plug-ins provided by device manufacturers include a user interface for device management and maintenance. This technology allows device manufacturers to develop their own host applications and control how users navigate the interface and what information is displayed. Recent technological advancements have blurred the differences between these two technologies in some aspects. EDDL has enhanced its graphical capabilities, "allowing users to draw charts and graphs. By using a unified data storage method, relevant information can be stored on the system hard drive and retrieved when needed in the future," Zielinski said. Piper of Foxboro stated, "These enhancements have begun to build configuration screens. Unlike the original simple parameter tables, users can now place various parameters on different screens, group them appropriately, and specify which parameters to select using drop-down menus. The user display, after these improvements, has become more like a table than a fill-in-the-blank format." However, no matter how enhanced Device Description (DD) technology is, there are still some limitations from the perspective of OEMs. Piper said, "Because each valve is different, we cannot develop a user interface for each valve, so this work has to be done by the valve manufacturer." He still maintains that FDT is the best technology to solve this problem. On the other hand, Wallace of Emerson believes that "EDDL technology has great potential to achieve maximum benefits at minimal cost." He also cited user support as evidence, stating, "Currently, there are approximately 1200 field devices using EDDL, while only about 110 devices use DTM." He added, "EDDL is a global standard, supported by almost all OEMs." Piper expressed a different view, stating, "Currently, with the exception of a few vendors, almost every system manufacturer has announced support for FDT technology." Wallace suggested providing some support for both technologies, saying, "My suggestion is to adopt EDDL technology as much as possible and make it the standard. Only consider trying DTM when EDDL, application packages, and technologies like snap-ins/snap-ons using EDDL are all unsuitable for the required functionality." [ALIGN=CENTER] Applying DTM technology will make it possible for device manufacturers to include features such as Microsoft Windows Help in their displays, as shown in this screen provided by Invensys Foxboro.[/ALIGN]