A Personal View of IEC 61850

By Scott Olson, POWER Engineers

It’s hard to convince intelligent folks to fix something that doesn’t appear broken. Take distributed network protocol (DNP) and IEC 61850, for example. When I first heard about IEC 61850 in the early 2000s, I thought it just another protocol that someone was promoting as the next great thing in the substation. It was gaining popularity in Europe and Asia but for some reason wasn’t getting much traction in the U.S. So, why not?

First, let’s lay some groundwork. As a substation protection and controls engineer, my first impression of the standard was that it sounded promising: an international standard that defined object-oriented, self-describing data designed to operate over a 10/100 million byte (MB) Ethernet. Interoperability was becoming a buzzword, and the idea that all substation equipment vendors would support this standard was starting to emerge. The replacement of electromechanical relays with communication-capable smart devices was becoming commonplace. It made sense, therefore, that with all the computing power going into substations, getting the equipment to communication should be easy.

Not so fast.

A Little History

In June 2005 I published an article, “IEC 61850: Where are We Headed with Substation Communications?” in POWERGRID International’s predecessor, Utility Automation & Engineering T&D. In that article I provided a simplified history of the preceding decade with respect to protocols in the U.S. utility market.

“Early on,” I wrote, “substation communications were all but nonexistent. Most (intelligent electronic devices) IEDs that had communication capabilities used proprietary protocols that made it difficult to move data from the IEDs to the (remote terminal unit) RTU to the (supervisory control and data acquisition) SCADA system. Also, it was nearly impossible to share data between IEDs. To fill this gap, data concentrators were developed that utilized different protocols on separate RS232 ports to poll data from substation IEDs. These legacy protocols, in general, tended to be simple protocols that were designed to be byte efficient.”

I argued that communications protocols such as PG&E 2179, Modbus and DNP had become industry standards. These were tag-based protocols where users accessed data by specifying a tag number or index number. The result was a reliable network architecture, but one that was needlessly complex. This complexity, however, did not keep DNP or Modbus from becoming widely accepted substation network protocols. Driven by user demands for intercommunications among IEDs, these protocols provided the logical initial solutions for open protocols. With the global move to Ethernet, the industry became interested in network solutions, and, as a result, DNP and Modbus quickly adapted to the TCP/IP format.

“In the meantime,” I wrote in the original article, “EPRI and others were developing utility communications architecture (UCA)—widely considered the grandfather of IEC 61850—as the future utility communications protocol. UCA has been tested and run through several pilot projects to confirm that an object-oriented, self-describing protocol can be used reliably over Ethernet. These tests have proven successful and have attracted a lot of interest, but there has been little action in the market.”

I concluded that as need dictated, the shift to Ethernet had been obtained but an object-oriented protocol for DNP or Modbus was ultimately unachievable. Yes, I realized that packetizing the serial protocol in an Ethernet fashion could serve the purpose, but it would never serve as a true solution to a robust Ethernet protocol. Time would tell whether utilities agreed with this assessment.

A Subjective View

Six years later, we are starting to see some movement in the U.S. market toward IEC 61850, but not much has changed. Why not? That’s what I wanted to find out. With my curiosity piqued, I and others from POWER Engineers formed questions to understand market attitudes. Several of us picked up our telephones, calling utilities across the country to informally assess whether IEC 61850 was on the companies’ radars.

Our survey had about 40 questions, which were conversational. We started each conversation with some casual introduction to IEC 61850 and then asked the person on the other end of the line if his or her utility was actively pursuing the standard. As you can imagine, the answer to that question could take us almost anywhere, and it did. Depending on the first response, we would then ask follow-up questions to improve our understanding.

After about 20 conversations with some knowledgeable U.S. utility folks, patterns started to emerge. The mix of utilities included investor-owned, federal, cooperative, public and municipality organizations. We recognize that this survey is not statistically significant, but the responses are instructive nevertheless.

Here is a brief summary of what we learned:

  • The IEC 61850 standard has station bus (MMS and GOOSE) and process bus (SMV) protocols. In no case had any utility implemented IEC 61850 fully. Those that had implemented one or more of the protocols in the standard had also hardwired critical signals (like the trip or synchronizing signals) because they didn’t fully trust the network.
  • Only three respondents had active, working projects and had included the IEC 61850 standard in future substation design specifications. Most of these were located in the Northeast and were likely to have a dual-primary, or a primary-backup protection scheme in place.
  • Three additional respondents were actively researching the standard and were planning projects that would include some portion of IEC 61850 within the next year. (We have spoken to others since the original survey, and this number is growing.)
  • About one-third of the respondents, or perhaps a few more, are watching to see how the IEC 61850 standard protocols perform and are planning to include some implementation in their substation designs within the next five years. Their key concerns are economics, making sure the standard is mature and proven, training their people to handle the transition and figuring out how to effectively test a networked protection system.
  • All remaining respondents were not planning to start any IEC 61850-related projects within the next five years. They seemed comfortable with existing protocols and saw no need to change. Some within this late-adopting group will consider the standard, but it will be some considerable time in the distant future.

During the course of the interviews, we tried to gather some sense of how much time and effort utilities invested in understanding the IEC 61850 standard and its protocols. It was evident that there was a wide range, so we decided to plot what we had gathered. Again, this was a subjective survey, so there are no scales. Some of the folks we visited with had no idea about IEC 61850 at one end, while others were highly informed. Plotting awareness of the standard against likelihood of implementation in the near future yielded Figure 1 on Page 56.

More Than a Protocol

In the meantime, POWER Engineers had been quietly testing substation relay equipment from dozens of vendors in an IEC 61850 technology lab to assess whether new equipment could be configured to work with the standard. We began tabulating our results and observations in a quarterly newsletter, which we sent out to a small list of people to generate discussion and interaction. We received a great email from one of our readers, who reminded us that there was a difference between a standard and a protocol—the latter being a component of the former—and that it was possible to implement IEC 61850 protocols without going all out to implement the standard.

“For example,” our reader offered, “61850 GOOSE messaging may be used between IEDs to eliminate physical wiring and increase speed of interaction between IEDs while continuing to use DNP to communicate upwards to SCADA and higher-level systems where slower communications updates are acceptable. This opens new applications for end users because of the GOOSE high-speed capability but would not necessitate a change in the SCADA communications infrastructure.”

It was such a great point to make: The migration to the IEC 61850 standard does not force the absolute replacement of protocols that are already in place. Solutions can be implemented that allow parts of 61850 to be added to the network while the legacy protocols continue to be used over the same network. For example, station bus protocol (IEC 61850-8-1) could be used to simplify the interface between IEDs, human-machine interfaces (HMIs), etc. within the substation network while continuing to use DNP interface to SCADA. As process bus (IEC 61850-9-2) devices become readily available, the opportunity to eliminate copper wiring between current transformers (CTs) and IEDs could provide tremendous savings opportunities and could be done independently from station bus implementations.

It Isn’t Broken

I’ve concluded that DNP, and many other protocols in use across our nation are useful solutions and don’t need to be replaced. Each of the legacy protocols currently in place for investor-owned utilities, cooperatives and municipalities serve a purpose within its existing system. However, we’re finding in our technology lab that it’s possible to integrate IEC 61850-related processes (process bus or station bus) without having to fully implement the entire protocol and still generate savings.

As substation equipment becomes smarter, data will proliferate. This immense amount of data needs to integrate into a future grand scheme that incorporates IEC 61850 inside the station, IEC 61968 for the distribution system, IEC 61970 for the transmission system, IEC 60870-6 between control centers, all operating within the context of the cybersecurity standard IEC 62351. (See Figure 2, above.) We aren’t suggesting DNP is broken, and we’re not advocating dropping one protocol in a dramatic switch-over to the bleeding edge. What we are suggesting: IEC 61850 is one of several resources available to utilities whereby they can efficiently move data between systems because there is now a common way to model that system data. It’s been selected by the National Institute of Standards and Technology and the Federal Energy Regulatory Commission as one of five priority standards for the emerging smart grid. It’s worth a closer look.

Scott Olson, P.E., is a project manager in the studies and analytical services business for POWER Engineers, a 1,300-person consulting engineering firm.

MORE INSIGHT AT http://power-grid.com

To read the first article referenced in this piece, visit the website and type “IEC 61850: Where are We Headed with Substation Communications?” into the search engine.

Get more info about IEC 61850 online as well by going to the website and typing “IEC 61850” into the search engine. You’ll find:

  • “Migrating Teleprotection Systems to Next-generation Networks” by Kobi Gol with RAD Data Communications,
  • “Protocols Driving Smart Grid Interoperability” by Tony Paine with Kepware Technologies,
  • Details on the company chosen by the Eastern Nebraska Public Power District Consortium to provide SCADA and distribution automation systems,
  • And more.

Visit us at http://power-grid.com for all the details.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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