- By Jonas Berge
- May 29, 2024
- Emerson
- Feature
Summary
Follow these recommendations to reduce emissions, improve energy efficiency, and stop overconsumption.
A lot has been said in the past 10 years about adding automation to plants for digital transformation of manual work. But the automation for the core process control (CPC) should also be modernized to require less manual intervention by production operators, for the plant to be more autonomous, to reduce instrument maintenance work, and to make the plant more sustainable.
Many old-style automation components remain in plants today because when they fail there is no time to review newer and better solutions, so they are replaced with identical components. Thus, there are still many mechanical instruments in operation. Those components were the best of their kind when originally selected, but today better solutions are available. Plants that do not keep automation up to date will be at a huge disadvantage in the long term. Instrumentation and controls problems have direct business impact. Modernizing automation help plants attain operational excellence. New plants being built now can use these technologies right from the start.
The core process control zone includes the distributed control system (DCS) and safety instrumented system (SIS), together referred to as the integrated control and safety system (ICSS), as well as the associated sensors and valves. These systems have rigorous management of change (MoC) procedures to preserve the robustness and safety of production. This article is about the automation in this CPC zone. But the CPC zone does play a part in digital transformation. Plants that successfully pursue digital transformation adopt the NAMUR open architecture (NOA) whereby data from the DCS is channeled securely through data diodes out to an independent monitoring and optimization (M+O) zone with automation for digital transformation of other functions. The data diodes make sure the security and robustness of the systems in the CPC zone are not affected. Open standard OPC-UA interfaces are used to make the DCS data available to the automation in the M+O zone. Thanks to this security, sensors and software apps can be added freely in the M+O zone.
Reducing manual intervention: Production
Instrumentation issues like failure, underperformance, inaccuracy, and lack of integration force production operators to manually intervene in loops that otherwise would be in automatic. Additional work causes stress, but various new, intelligent field instrumentation, controllers, and software components are available to help.
Transmitters with moving mechanical parts are susceptible to wear and failure, and when they do fail, production operators are forced to operate loops in manual. This, in turn, causes off-spec product, higher energy consumption, and operator stress, which may lead to mistakes. For example, displacer type interface level transmitters have moving parts. The recommendation is to upgrade these positions with guided wave radar (GWR) level and interface transmitters (Figure 2) that have no moving parts whenever conditions permit.
Another mechanical example is turbine and positive displacement (PD) flowmeters. The recommendation is to upgrade these positions with magnetic, vortex, or Coriolis flowmeters with no moving parts. As a result of more reliable instruments, loops stay in automatic for greater sustainability and reduced off-spec product, plus operator stress is reduced. In addition, many new instruments now support Bluetooth wireless communication that enables configuration, calibration, and diagnostics at the device using a phone, tablet, or laptop.
When the process cycles or deviates from setpoint, it could be due to control valve issues like high friction or high/low air supply pressure. Or the problem could be elsewhere in the loop. When analog control valve positioners or I/P converters are used, production operators cannot tell there is a valve issue because there is no diagnostics or position feedback. So, production operators put the troubled loop in manual. Again, they will experience the same manual challenges described previously.
The recommendation is to upgrade all control valves with smart valve positioners with valve performance analytics. Valve issues can be verified on the positioner display or over Bluetooth from a mobile device as explained earlier. As a result of diagnosing and fixing valve issues, loops can be returned to automatic with the same benefits described previously.
Actions that cannot be made directly on the operator console are associated with high stress, workload, and poor health. High levels of stress lead to errors. A good example of this is a manually actuated valve. This was acceptable in the past but not anymore. The recommendation is to upgrade manual valves by adding actuators. As a result of operation from the operator console, workload and stress are reduced.
Inaccurate transmitters make production operators set setpoints with conservative “comfort margins” to not cross limits. Comfort margins cause quality giveaway and high energy consumption. For example, ultrasonic or differential pressure (DP) level transmitters, turbine or PD displacer interface levels, remote seals or temperature sensors direct to system input cards each have their accuracy challenges.
The recommendation is to upgrade these positions with new sensing technology such as non-contacting 80 GHz frequency modulated continuous wave (FMCW) radar for level (Figure 3), magnetic, vortex, or Coriolis flowmeters, electronic remote sensors (ERS) in place of remote seals in most applications, GWR for interface level, and temperature transmitters close to the temperature sensors. For DP flowmeters, upgrade the DP transmitter to a high accuracy and stability model. With more accurate measurements, plants see reduced production cost and greater sustainability.
Package units and skids connected to the main distributed control system (DCS) through hardwiring or RS-485 networking carry limited information, like a single common alarm, to the production operators. Those operators then are forced to send someone out to the module for closer inspection when an alarm occurs. This causes operator stress, potential mistakes, slower problem resolution, and production downtime.
The recommendation is to upgrade the package unit controllers and DCS to use Ethernet, OPC-UA, and Module Type Package (MTP) integration technology (Figure 4). With the complete set of information from the package unit, plants reduce operator stress and production downtime.
Pressure switches only have an on-off contact output, so there is no telling if pressure is ever close to the limit or how fast it is changing. Production operators get no early warning (no prediction). In addition, there is no self-diagnostics so production operators cannot tell if it has failed. This in turn leads to operator stress. When in doubt, production operators must request a manual check on signal validity. The recommendation is to upgrade these positions to pressure transmitters with self-diagnostics flagged as 20 mA. For example, American Petroleum Institute (API) standard 682 recommends transmitters instead of switches for mechanical seals.
Similarly, proximity switches are sometimes used for position feedback, but they only tell you if the valve is fully opened or closed, and there are no self-diagnostics so production operators cannot tell if a switch has failed. This in turn leads to operator stress. When in doubt, production operators must request a manual check on signal validity. The recommendation is to upgrade these valves to position transmitters. With more information, plants can reduce operator stress and increase safety
Mechanical controllers, as found on some control valves in some corners of most plants, are isolated because they are not integrated with the operator consoles. Production operators must go to the field to manually check the pressure or change the setpoint. This leads to operator stress. The recommendation is to upgrade these valves to electronic controllers with networking, enabling remote setpoint and process monitoring from a central location. This helps plants reduce operator stress.
Reducing the workload: Maintenance
There are thousands of instruments in a plant, so it is critical they are reliable, requiring minimal attention and that any necessary maintenance is made easy. This is over and above what digital transformation can do for equipment reliability.
The mechanical servo and float-and-tape tank gauges, displacer interface level, turbine and PD flowmeters, turbine flowmeters, and mechanical controllers have moving parts and therefore are susceptible to wear and failure. When they do fail, the maintenance team must replace the failed device, resulting in increased workload and maintenance cost as well as causing production downtime. The recommendation is to upgrade these positions to radar level gauges; GWR level and interface level transmitters; magnetic, vortex, or Coriolis flowmeters; and electronic controllers, respectively.
Float-level switches used to detect high or low level also have mechanical moving parts. The recommendation is to upgrade these positions to vibrating-fork-level switches without moving parts.
Turbine flowmeters may also be used for custody transfer. Also, for these positions, the recommendation is to upgrade to custody-transfercertified ultrasonic or Coriolis flowmeters without moving parts.
Displacer transmitters may also be used for density measurement. For these positions, the recommendation is also to upgrade, in this case to vibrating fork density transmitters.
Lastly, old-style control valve positioners and position transmitters have mechanical position feedback linkages, which are susceptible to wear and failure. The recommendation is to upgrade these valves to positioners and position transmitters with non-contact position sensing with no moving parts. As a result of more reliable instrumentation, plants enjoy reduced maintenance cost and reduced process downtime
Replacements like temperature sensors in thermowells or pressure transmitters with manifolds cause little downtime. However, replacing an inline flowmeter, bottom-mounted level transmitter, an instrument on a pressurized tank, or a valve positioner causes significant downtime. For these positions, it is even more important to have a reliable instrument with no moving mechanical parts.
Flowmeter calibration is labor-intensive because the flow sensor is installed inline and must be pulled. Often, the flowmeter must be shipped to an external lab, possibly overseas. This incurs high maintenance cost and production downtime during the swap. The recommendation is to upgrade to flowmeters with smart meter verification (SMV) to predict calibration drift to assess the need for flowmeter calibration or whether calibration can be scheduled later, all without interrupting the process. By optimizing the calibration schedule, plants reduce maintenance cost and production downtime.
As explained previously, with analog control valve positioners or I/P converters, there is no telling if control loop setpoint deviation or hunting is due to the control valve. There is a risk of unnecessarily overhauling the valve, adding to the workload and maintenance cost as well as causing production downtime. The recommendation is to upgrade all control valves with smart valve positioners with valve performance analytics. Valve issues can be verified on the positioner display or over Bluetooth from a mobile device. By verifying valve issues, plants can avoid unnecessary overhaul or optimize a necessary overhaul. Plants reduce maintenance cost and production downtime.
Devices connected to the DCS through hardwiring provide very limited information, for example, in the case of drives and motor starters. Maintenance technicians must go to the marshalling cabinet or motor control center (MCC) to check from the local display. Similarly, interaction becomes very slow when RS-485 networking is used in cases such as instrumentation through HART multiplexers. This adds to the workload.
Another challenge is that as servers go obsolete or fail, new servers do not support RS-485/RS-232. Many new replacement devices no longer support RS-485. The recommendation is to upgrade devices and DCS to use Ethernet networking with the appropriate protocol like PROFINET for motor controls and HART-IP for instrumentation and infrastructure. As a result of the complete set of information from the device, plants reduce maintenance cost and production downtime.
Improving plant sustainability
Automation has a key role to play in the sustainability of industrial plants. Solutions for several challenges such as loops in manual and comfort zones are already mentioned. But even more can be achieved by modernizing automation. And this is over and above what digital transformation can do for sustainability.
Direct spring pressure release valves (PRVs) start lift and reseat well below set pressure. This, in turn, causes emissions, flaring, and product loss. The recommendation is to upgrade to pilot operated PRVs (Figure 5), which have more precise pressure handling thus reducing release and flaring. As a result, plants minimize product loss and enhance sustainability. They are also less sensitive to back pressure.
Manual gas leak inspection with portable testers for greenhouse gas (GHG) emissions like methane is time consuming. This in turn leads to delayed detection and response and therefore excessive emissions. It is also labor intensive, which leads to field operator stress. The recommendation is to deploy ultrasonic, infrared (IR), or non-dispersive infrared (NDIR) sensors to detect gas leaks. As a result, plants improve safety and sustainability.
Simple proportional-integral-derivative (PID) control does not handle multiple interacting loops, multiple constraints, and difficult process dynamics such as long deadtime, long time constants, and inverse response. Production operators are forced to make frequent manual adjustments, which leads to operator stress and mistakes. This in turn causes off-spec product, high energy consumption, and low throughput. Combustion control is one such example. The recommendation is to upgrade to a DCS with advanced process control (APC) software for model predictive control (MPC) based on dynamic matrix control (DMC) supporting multiple inputs, outputs, and constraints. For selected loops, this will reduce process variability and keep the process within constraints. As a result, plants reduce operator stress, reduce off-spec product, and improve sustainability and throughput.
PRV in applications with back pressure such as from flare headers often use internal bellows. When the bellows eventually fail, the PRV will vent process gas straight to the atmosphere contributing to emissions and potentially causing fires and explosions. The recommendation is to upgrade to PRV with backup piston. The backup piston can reduce emissions by more than 90 percent in the event of a bellows rupture, and it ensures balanced operation. As a result of the better back pressure handling, capacity, and reliability, plants reduce emissions and product losses, while improving safety and sustainability. Bellows leak detection can also be added.
Improving plant safety
Both functional safety as well as occupational safety and health will benefit from automation modernization. Many modern instruments recommended in this article like the tank gauging system, radar level, GWR interface level, level switch, ERS, temperature and position sensors, as well as Coriolis, magnetic, and vortex flowmeters are available as safety integrity level (SIL)-rated. This means they have a low failure rate and high diagnostic coverage, making them ideal for safety instrumented functions (SIFs). As a result, plants can improve safety.
High aerodynamic noise is created by turbulence in gas, steam, or vapor flow in high pressure-drop valves. Traditional valve trims and insulation do not help sufficiently. Noise is an occupational health issue, so requirements have become more stringent. The recommendation is to upgrade to control valves with valve trims and cages designed and built using additive manufacturing for low noise with minimal pressure drop. Additionally, a modal attenuator (Figure 6) can be inserted to act as a silencer with no pressure drop. As a result, plants improve occupational safety.
A smart plant modernization workshop
Your plant may have some but not all these problems. And it may have other problems. Conduct a smart plant automation modernization workshop to uncover challenges around manual loop intervention, instrument maintenance, sustainability, and safety. Based on the workshop findings, replace old automation components across the plant before they fail. But remember: Each modernization campaign and application should be validated. Do not replace just because there is something new.
This feature originally appeared in the May Sustainability issue of AUTOMATION 2024.
About The Author
Jonas Berge is an ISA Fellow and the senior director of Applied Technology at Emerson Automation Solutions based in Singapore. He is a trusted advisor for plants and EPCs to adopt new technologies moving the industry forward with digital transformation. He has more than 30 years of experience and is a subject matter expert (SME) in digital transformation (DX)/Industrie 4.0 including data management, analytics, wireless sensors, and the Industrial Internet of Things (IIoT) with particular emphasis on sustainability and decarbonization.
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