Building a new plant can take years and often comes with its share of technology problems related to system configuration, network integration and device compatibility. Avoiding technical trouble during design and startup of a new facility is a critical part of the plan. To that end, streamlining the programming and commissioning of thousands of field devices was on the forefront of Andy Bahniuk’s mind during the expansion of the Shell Canada Scotford refinery and chemicals plant in Fort Saskatchewan, Alberta.
Shell Canada runs the Athabasca Oil Sands Project (AOSP) comprised of two mines excavating ore containing bitumen (a semi-solid form of crude oil) from the tar sands. The surge in oil sands production required an expansion of the processing facility. In 2004, Shell Canada began to build out the Scotford Upgrader, the feedstock for the refinery that upgrades bitumen from the Shell Albian Sands and converts it to synthetic crude. The synthetic crude is shipped to refineries, where it is further processed into fuel products like gasoline.
Originally supporting a 155,000 barrel per day (bpd) capacity, in 2010 Shell authorized an additional 100,000 bpd expansion to the Scotford Upgrader facility. That’s when the Shell team got hit with a technology roadblock. The measurement and control devices were supposed to arrive pre-configured, but did not. The challenge: How to safely program and commission more than 1,500 intelligent devices from 26 different vendors in a timely fashion so as to not throw off the engineering schedule.
Working with its distributed control system (DCS) vendor Honeywell, Shell tapped into the company’s Field Device Manager (FDM) software, an asset management system that enables remote configuration and maintenance of smart field devices based on HART, Profibus and Fieldbus Foundation protocols.
Using the Honeywell system, the Shell team set up all of the devices in about three months and conducted testing for another four to six months, saving the company a lot of time and money, says Bahniuk, a control system specialist and a lead instrumentation technologist at Shell Canada.
The FDM tools simplified the configuration and management tasks for the engineering team. “It is all transparent to the end user,” Bahniuk says. “FDM gathers the HART information and puts it into one place for easier troubleshooting and monitoring.”
It’s true, Honeywell’s FDM asset management system played a huge role in the quick commissioning and startup of so many different instruments, but it is the technology inside—in the form of the Field Device Tool (FDT) standard—that enables the asset management system to easily configure and maintain intelligent field devices.
FDT creates a common communication method between field devices and control or monitoring systems that are used to configure, operate, maintain and diagnose intelligent field instrumentation in both factory and process automation applications. It is not a communication protocol, but rather an interface that is an IEC standard (IEC 62453) and an ISA standard (ISA 103). In essence, it is the “secret sauce” that regulates data exchange between devices and automation systems. Devices can be configured, serviced and maintained via a standardized interface, independent of manufacturer, device type or communication protocol. And, when device and control system suppliers comply with the FDT standard, achieving seamless interoperability is easy.
“We set out to create a standard that allows device manufacturers and higher-level systems to integrate together, regardless of the network,” says Glenn Schulz, managing director of the FDT Group AISBL (Association Internationale Sans But Lucratif), which developed and maintains the FDT specification. “We focused on process initially, but have now moved into factory automation as well.”
FDT is not a new standard; it has been around for more than 10 years and is supported by more than 7,500 different devices from measurement and control suppliers around the world. But its presence and significance often goes unnoticed by the average end user—and that’s on purpose.
“The customer does not need to know the technology details,” says Manfred Brill, software governance senior manager at Schneider Electric and chairperson of the FDT Group factory automation committee. In some cases, such as with Bahniuk, the user is familiar with the vendor’s technology, but FDT is not a familiar term. Nor should it be, Brill says, as it is up to the automation supplier to leverage the FDT standard as an intrinsic part of its product to deliver a seamless user experience for device commissioning and management.
Florian Grätz, product owner at Kuka Robotics, concurs. “Most of our customers don’t even know they are using FDT,” he says, adding that it is nonetheless an extremely important part of the robot controllers.
“Our customers are using a wide range of fieldbus technologies. In Europe, we find a lot of Profinet and Profibus; and in the U.S., it is mostly DeviceNet and EtherNet/IP,” Grätz says. “We had to find a way to cover all of the fieldbus protocols within our engineering suite.” FDT eased integration for the Kuka engineering team by allowing them to move away from hardware-based fieldbus integration, in the form of PCI cards, and over to the FDT software specification.
More importantly, Kuka was able to enhance the end user experience. “From the customer point of view, our robot controllers are more reliable because we are using less electronic parts, which decreases the risk of electrical breakdown,” Grätz says.
Indeed, end users appreciate the benefits of reliability and easy interoperability. For example, while Shell’s Bahniuk is not familiar with FDT per se, he is well aware of what it can do when embedded in field devices and control systems.
First, FDT is what enables the configuration of device parameters that can be defined even offline. The parameter set is created or changed and stored, so when the field device is connected during commissioning of the project, the parameter set can be loaded to the device—saving an enormous amount of time.
Second, Shell relies on HART technology to connect field devices monitoring pressure levels and temperature across the pipeline and at the Scotford Upgrader. During the long, cold Canadian winters, the temperature can drop to -45 0C, which could freeze instrumentation in the field. The transmitters, therefore, are mounted in insulated enclosures with heaters. The centralized Honeywell asset management system can monitor the status of the heaters and transmitter temperature variables, alerting maintenance if something starts to freeze.
“There are from four to 20 signals coming into the DCS, but we strip off the HART signal to get diagnostics from the device,” Bahniuk says. This preventive maintenance capability has saved the company more than $200,000 per year. “Every fall we would have to send people out to the field to check the thermostats and heat enclosures, but we don’t have to do that anymore because the information from the device tells us if we have an issue.”
How FDT works
FDT technology consists of two main components: the Frame, an embedded component of the control system suite or standalone application; and the Device Type Manager (DTM), a device-specific application that launches within the frame.
The DTM is a device driver that gives manufacturers control of the attributes displayed for the device. It includes diagrams and methodologies for configuring FDT-compliant devices. Without FDT, device information access could be restricted by the control system supplier. But with FDT, an end user can pick best-in-class devices and not be constrained by support for that particular product, FDT officials say.
The Frame Application, on the other hand, is a software window that provides the user interface between the DTM and host applications, like asset management tools, PLCs or a DCS. In addition, the Frame Application connects the DTM to the correct communication gateways and protocols. A single FDT Frame Application supports 17 networks and field communication protocols, including HART, Profibus, Foundation Fieldbus, Modbus, DeviceNet, Interbus, AS-Interface, Profinet, IO-Link, CC-Link, ISA-100 wireless, and more.
If there are several networks on the plant floor, no problem, as information will be delivered despite a disparate infrastructure. “The standard is written such that the end user has no awareness that tunneling or routing through different networks is taking place,” FDT’s Schulz says. “To them, it’s as if they are directly connecting to that device and can access all of its intelligent features.”
In the most recent update of the specification, called FDT2, enhancements with security and performance were added, while maintaining backward compatibility to existing DTMs and Frame Applications. Developed on the Microsoft .NET 4.0 framework, FDT2 includes an improved user interface with graphical representations of device parameters, including additional device wizards and diagnostic tools that can be developed by the device supplier. The graphical user interface (GUI) is separate from the business logic, creating a lightweight client that can be automatically updated from the DTM on the server.
A lightweight client may very well be the precursor to an FDT-enabled mobile application, which officials say is currently in the works. “The plan for the mobile app is to enable maintenance people in the field to access other devices and not be bound to an engineering or management system somewhere in the office,” says Schneider Electric’s Brill. “We are also working on an interface between FDT and OPC UA,” he adds, which could be used in a mobile environment, as well as an integration tool to manufacturing execution systems.
Also in FDT2, there are more security safeguards built in, including tamper-proof protection. All applications created in compliance with FDT2 specifications are digitally signed, providing proof of data integrity. And there is granular DTM security with enhanced user rights added to the security settings.
FDT2 also includes speed and performance improvements, officials say, and a set of common components that provide a supplier with the software needed to start developing FDT2-compliant products. Though all DTMs operate using a similar menu and visualization scheme, not all DTMs are created equal, as some suppliers will develop broader functionality that can help users improve troubleshooting and maintenance.
Though FDT is recognized as a communication catalyst, providing interoperability between disparate devices on different networks, another important—and often overlooked—function is its ability to provide diagnostic information on devices in the field. “The real benefit from the end user perspective is the diagnostics,” Schulz says.
Digging deep into device diagnostics
At the MOL Group’s Danube refinery in Százhalombatta, Hungary, FDT has been in use for 10 years specifically for device diagnostics. The FDT rollout in 2005 was initiated to solve a problem related to the refinery’s computerized maintenance management system (CMMS), which was not delivering signals, indicating a problem in the field. It was then that the company overhauled its CMMS with a new asset management system that created an online diagnostic system in which control valves and instrument devices send signals directly over HART and Foundation Fieldbus to plant maintenance systems and the three different DCSs in the refinery. “We have completely integrated systems, not for the whole refinery, but for the critical devices in the field which send signals that drive notifications,” says Gábor Bereznai, head of control and electrical engineering at MOL’s Danube refinery. “We use DTM to dig deep into the problems.”
When things are not behaving properly with an instrument or a device, the DTM can indicate that something is not right and provide a list of possible causes.
For example, when the pressure control was slow on one distillation column, it led to the assumption that a valve was stuck and in need of removal and repair. But technicians used device diagnostic data to interrogate the valve and find current-to-pneumatic damage in the intelligent positioner, but not the whole valve. The fix took 30 minutes of work and saved the plant at least two days of unscheduled downtime, which could have been a loss of several hundred thousand dollars.
“The real function of the system is to avoid breakdowns and slowdowns,” Bereznai says.
It is also good for preventive maintenance. Before online device diagnostics, the MOL team would automatically repair or replace about 60 percent of the control valves during a scheduled maintenance shutdown, but some valves were likely removed unnecessarily. Having a better handle on valve performance means pulling fewer valves at turnaround time, reducing maintenance costs. “Ten years ago, we pulled all of the valves,” Bereznai says. “Now, we pull two dozen instead of 200, saving $20,000 to $70,000 per turnaround.”
A substantial savings—all from a deep-seated, and slightly misunderstood, standard called FDT.