10 steps to a smoother automation system upgrade

When migrating or upgrading your automation system, don’t forget to examine this group of areas outside of the HMI, controllers, and I/O. These suggestions will help you identify and deal with lurking problems early in the process.


Figure 1: Smart instruments should be connected to the new automation system and tested for compatibility during the early stages of an automation system upgrade project. Courtesy: YokogawaIf you’re in the process of upgrading your automation system, or contemplating such a task in the near future, your primary focus is probably on the HMI, the controllers, and the I/O—and rightly so as these are critical components to address in a system migration. But there’s much more to an automation system than these hardware components, and these secondary areas can be the source of many problems if due diligence isn’t performed in the planning stages.

One of the best ways to examine all areas of the automation system prior to undertaking a major automation upgrade project is to perform a front end loading (FEL) evaluation. A FEL evaluation is a type of analysis that evaluates all aspects of an automation system upgrade or other project. Among other deliverables, it should include a list of project tasks with durations, and an overall project schedule.

Most end users will work with an outside service provider to produce the FEL evaluation because they often don’t have the available manpower. The right service provider will have produced many FEL evaluations for automation system upgrade projects, and can thus help the end user to produce a thorough study in an optimal manner.

A FEL evaluation will help develop a budget and justify the project. It will also reveal potential problems, and help prepare end users for the daunting task of migrating their obsolete DCS or PLC-based automation system. In short, it should provide a map to success with the destination in mind.

In most cases, the amount of time and effort invested in a FEL evaluation is directly proportional to overall project success. Unfortunately, many end users view this stage as an optional task for an automation system upgrade, and perhaps even a distraction. Scrimping on the FEL evaluation not only increases risks, it also can result in missed opportunities for improvements and enhanced long-term sustainability. By contrast, a thorough FEL evaluation will identify potential problems and help ensure that the project attains its goals.

10 areas outside the lines

When the main architecture is developed for an automation system upgrade, the primary components are always the HMIs, controllers, and I/O. Most of the time and effort in the planning and budgeting stages is spent on these key components, often to the detriment of the balance of the system, those areas that fall outside the lines.

A properly executed FEL evaluation will shed light on 10 important secondary areas, which are listed in Table 1 and discussed below.

Field devices and infrastructure

Field equipment and wiring primarily consists of four parts:

  • Wiring, conduit, and cable tray
  • Panels, cabinets, marshalling panels, and junction boxes
  • Instrumentation, including inline devices, analyzers, transmitters, etc., and
  • Mechanical equipment, including motors, valves, drives, and other field devices.

All of these items must be examined to ascertain acceptable physical condition and proper documentation. In addition, instrumentation and mechanical equipment must be examined and/or tested to ensure proper interface with the new automation system’s I/O and digital communication interfaces.

The overall condition of field wiring, including terminations, labeling, and grounding, should be assessed during the FEL process. If any areas are not up to standards and in good working condition, plans and budgets should be developed to rectify any deficiencies and defects.

When the automation system is up and running, the status of various field devices such as motors, valves, and position switches is determined by hardwiring these components to automation system inputs. So, the interfaces between these devices and the inputs must be tested to ensure proper voltage levels and electrical isolation.

Similarly, valves, motors, and status lights are driven by automation system outputs. Again, compatibility must be ensured so that each output can drive or actuate its associated device.

Interfaces to automation system analog I/O can be a particular problem area. A 4-20 mA output on an older automation system may have been able to drive more instruments in a loop connection than the new automation system’s 4-20 mA output. This issue would be minor if uncovered in a FEL evaluation, but major if found during commissioning. Moreover, analog inputs must be examined and sometimes tested for compatibility. For example, an older DCS might have accommodated thermocouple types that are no longer in widespread use, and as such may not be supported by the new automation system.

Most plants have smart instruments and analyzers with their own network connections to the automation system (see Figure 1), another area that must be examined in detail during the FEL evaluation. 

Network infrastructure and connectivity

Modern automation systems connect to a variety of other systems and components in various layers including:

  • Control layer—ancillary control systems on process skids, emission monitoring systems, building automation systems, etc.
  • Enterprise layer—historian, MES, ERP, corporate networks, etc.
  • Field device layer—HART, Fieldbus, Profibus, DeviceNet, etc., and
  • Other—lab systems, remote access, analyzers, advanced process control devices, etc.

The physical infrastructure, including the fiber/copper backbone, network devices, wireless hardware, and other items, must be examined to ascertain acceptable condition and proper documentation. But this is only the first step, as compatibility issues can abound, even when the new automation system supports the very same protocols as the old automation system.

The main interfaces at each layer should be tested to ensure that communications can take place in an acceptable manner with performance equal to or exceeding the existing system. The new automation system must be able to support all of the existing communication protocols, either directly or through protocol converters. In some cases, it may be more cost effective to upgrade or even replace systems and components that can’t easily be interfaced to the new automation system.

For example, if there is a small cluster of instruments with a different fieldbus protocol than the majority of instruments, it may be better to replace these oddballs, as opposed to adding a protocol converter to connect them to the new automation system.

The older automation system will often have controllers and smart devices such as instruments and drives supplied by the same vendor. If the new automation system is purchased from a different vendor, in almost all cases the digital interface to the smart devices will be more limited in functionality, even if the protocol is nominally the same. Provisions must be made to operate the system with this reduced functionality, or to replace the smart devices.

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Allen , TX, United States, 09/06/13 02:03 PM:

Thanks for the great article. I'm also a big fan of FEL activities. Do you have any metrics relating to the cost of FEL as a percentage of the TIC? I suspect that it's in the 3%-5% range (meaning that it's definitely worth the money), but I don't have data to back that up.
Jonas , , 11/10/13 09:55 AM:

You can modernize any plant with new wireless measurements on any system, regardless of how old, because the wireless gateway supports multiple protocols such as Modbus/RTU, Modbus/TCP, EtherNet/IP, and OPC for process variables as well as HART-IP for intelligent device management (IDM) software past of the asset management system such as for calibration trim, configuration/setup, device diagnostics, and internal variables etc.

Very often the asset health information, the energy consumption readings, and HS&E status etc. do not even go into the basic control system (DCS) or the safety system (SIS), this new data from wireless sensors often go into the asset management system (AMS). This is tons of new data received by deploying sensors everywhere; “pervasive sensing”. These new sensors can easily be added to an existing plant to modernize that plant because not only do you eliminate power wiring and signal wiring for these sensors, many of them have non-intrusive mechanical installation. For example, to monitor the position of the bypass valves or any other control valve, on/off valve, or hand valve, a wireless transmitter simply screws onto the outside. It is non-intrusive. No process penetration. Similarly, there are clamp-on temperature sensors that measure the surface temperature of the pipe. This is good enough in most asset and energy monitoring applications, and is totally non-intrusive. Clamp-on temperature sensors can be used when thermowells are not available. Acoustic transmitters to monitor if a steam trap is passing steam wasting energy, or blocking condensate which could damage equipment or cause insufficient heating, simply straps onto the outside of the pipe, again non-intrusive. It can also strap onto a relief valve to detect release, or another valve to detect leaks. Vibration sensors for wireless vibration transmitters can either be screwed on, stuck on with epoxy, or even a magnet without any process penetration. Pressure transmitters often take the place of mechanical dial gages so again no new process openings required. This makes installation of these additional sensors low cost and low risk.

Most kinds of wireless transmitters are already available: pressure, flow, DP level, valve position, pH, conductivity, on/off contact, radar level, vibration, temperature, multi-temperature, and acoustic as well as level switch and even on/off valve actuation

Plant modernization is a new business opportunity for EPCs. EPCs can go back to all the plants they have built over the past 20-30 years and offer plant-wide modernization by deploying a second layer of automation based on Wireless transmitters for asset monitoring, energy conservation, and improved HS&E beyond the P&ID. A formal process starting from audit, through FEED, detail design, installation, commissioning, and handover is available.

Having said that, if you get a new control system, you can get one with native integration of wireless transmitters, enabling you to access the PV directly from a wireless transmitter without going through Modbus register, EtherNet/IP instance & member, or OPC item data mapping. Getting a system with native support for wireless could be one more reason for migrating.
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