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IEEE: The expertise to make smart grid a reality

Interview with Dave Bassett

David Bassett is an IEEE Smart Grid technical expert, a Senior Member of IEEE and a member of the IEEE Standards Board. He has helped lead development of IEEE 1547™ standards and has contributed to IEEE 2030™ standardization efforts. Recently retired, Bassett is engaged, as an industry consultant, in utility phasor measurement unit projects and Aurora event analysis.

In this wide-ranging interview, David Bassett asserts that utilities need to come up with new and imaginative ways of presenting energy data to customers to encourage customer participation in Smart Grid. He discusses challenges associated with connecting customer-owned generation to the grid, solutions needed for controlling distributed resources, and the communications and computational technologies Smart Grid will require.

Question: You have said that it will take not only time and effort to realize the Smart Grid but that it will also take a lot of imagination. How can the industry be imaginative about Smart Grid?

We need to come up with imaginative ways of presenting Smart Grid data to customers. We must present it as “information,” not data. And we must make the information available in user-friendly ways that encourage customers to access it for their own personal use or load it onto their own spreadsheets to perform their own analyses of it.

The Green Button initiative, which some utilities offer, is a good step in this direction. As more energy information becomes available, entrepreneurs must innovate to find ways to encourage customers to use the information to enhance their energy savings. Companies could create applications that customers can use to project household energy consumption under varying use-cases or to estimate cost savings for specific time-of-use strategies. Other applications could enable consumers to compare their household energy usage with that of other, similar houses in their neighborhoods, for example.

These types of applications will really require new and creative thinking. But utilities must be extremely careful to ensure that everyone’s privacy rights are protected. The data must be made anonymous and non-traceable and secured end-to-end, beginning at the point where the measurements are taken and continuing on throughout the network as the data is transmitted, stored and aggregated and finally presented to customers via software applications.

Based on some of the lessons you’ve learned from large utility projects, what advice can you offer to help ensure the success of Smart Grid projects?

The first thing to keep in mind is that projects typically do not proceed as smoothly as expected. For example, people often don’t anticipate that buildings or trees might interfere with radio signals from metered equipment. Better research and planning can avoid these types of surprises. Also, there have been instances when devices, based on paper studies, were expected to work well together but ultimately proved incompatible due to manufacturers’ variations in how they used interconnection protocols. This problem has been addressed by standards such as the IEEE 1815™-2012 Distributed Network Protocol 3 (DNP3) standard and others, so interoperability is becoming easier to implement.

Secondly, Smart Grid will change many routines in the industry. As the industry automates many distribution functions, utilities will need to modify many of their standard work methods and safety procedures accordingly. This will require a tremendous effort. The industry is progressing from a system that once relied on simple, electromechanical or hydraulic devices to a system that employs thousands of very small computers for a wide range of functions. Personnel must understand all these capabilities and change their routines to work with this new equipment.

What are some of the challenges companies and customers must grapple with when it comes to connecting non-utility generation to the grid?

In general, customer-owned generation units, especially small systems, haven’t evolved sufficiently for full integration into the Smart Grid. The industry is working to define a smart inverter that will control and regulate output for these systems and of course the IEEE 2030™ and IEEE 1547™ standards provide guidance for many of the interoperability and interconnection capabilities these implementations will need. But the systems require some form of communication between the distributed resource and the utility. Unfortunately, appropriate communications infrastructure is not always available, especially for smaller-scale customer-owned sites, which limits utility interactions with these resources.

Test cases for some city and community projects have shown that some significant benefits can be realized from installations that incorporate the necessary communications capabilities from the ground up, when the sites are designed and built. And larger investments, such as utility-grade installations that use equipment integrated with communications technologies, can provide direct interaction between the distributed resource and a utility control center. A few of these installations are being tested in conjunction with the draft IEEE P1547.8 standard, which will provide best practices for the implementation and enhanced use of distributed resources. The standard, which should be ready for balloting in late 2013, will help increase penetration of these resources.

What general strategies will utilities use to control distributed resources?

Interestingly, the overall strategy to control distributed resources in the Smart Grid is not complete. Even though a utility might have a Smart Grid in place and distributed resources reporting back to a central location, that central location actually may not be set up at this time to handle the modeling and control of the distributed resources. There are some test cases in which sufficient infrastructure and communications capabilities exist, and we will learn a lot from these test cases, but these are specialized deployments and a general solution is not yet available.

Vendors and researchers are working on solutions but these must address what is possible or practical to roll out into the real world. As I mentioned, communications capability in a lot of cases is lacking. The land that’s available for a large-scale solar field, for example, will likely be found in a remote location that does not have high-speed, broadband communications. Innovators will find ways to address these situations by using radio or microwave or other alternatives to link a site, but these approaches are not justified for small installations. And as I said, there will be a lot of smaller installations contributing to the grid that will need communications capabilities. Innovations that provide one-to-many high-speed or broadband communications capability and other potential options offering lower-speed one-to-one communications capability may provide a significant boost to the commercialization of these small facilities.

How far along are utilities in the process of enhancing their substation protection and control functions with Smart Grid technologies? What more needs to be done?

Utilities are just scratching the surface of their abilities to enhance substation protection and control functions. There are some functions, such as predictive maintenance, which are very well established, but event-driven functions, such as adaptive protection and controls, are still in the research or development stages.

Smart Gird will produce data that can improve substation performance, but it will require suitable hardware and software to use this information to perform the needed control actions. Some greenfield substations that have been built entirely with the newest state-of-the-art equipment can perform many of these functions, but these installations are rare.

We’re also limited by our aging electric infrastructure. Many electromechanical relays have been in service for 60 years or more. They still work fine but they are dumb devices. Until a significant number of substations are upgraded with smart sensors, smart relays, and Ethernet communications, utilities won’t realize all of Smart Grid’s advantages. Utilities are beginning the upgrade process, but they must start with small and experimental installations to see what works and then they’ll roll these technologies out in phases. The implementations will be gradual.

Phasor of measurement units, the most advanced sensors for Smart Grid, are being installed strategically on some parts of the U.S. transmission system and more of these sensors will be deployed in the coming years. What will it take for utilities to make full use of these smart devices?

Phasor management units take measurements of grid operations 30 times per second or 108,000 times per hour. On large installations these sensors could generate a terabyte of data every week. This is an incredible improvement over today’s SCADA devices, which typically take a single measurement every five or 10 seconds. PMUs also time-stamp each measurement so data from different utility systems can be combined and synchronized.

But the industry needs to be able to work with this information. Researchers are developing data visualization tools that utilities can use to understand and react to this data, and future technologies will use the data for automated, real-time controls. The goal is to have all of this data from across the United States filtered and delivered to the North American SynchroPhasor Initiative to provide a comprehensive, real-time view into the country’s power grid.

Utilities will need robust high-speed communications networks that guarantee low-latency and high levels of reliability. They’ll need to detect vulnerabilities and intrusions and encrypt data to ensure it is secure. In fact, the data may need to be treated as a cyber asset.

So there are some very serious communications and computational needs involved with transmitting this data around and storing it for later use. The industry wants to use this data, for example, to analyze grid operations before and during outages to find ways to improve future grid performance. This will be a tremendously exciting area of research.

You’ve recently retired after 40 years of service in the industry. Are there any other key messages you’d like to convey to the industry?

I’d like to put in a plug for getting some new engineers. In a way, we’re at a disadvantage in this industry because a lot of people think that working as a utility engineer is boring. But it really is an interesting profession. I’m now consulting to the industry and I can say that this is the most exciting time to get into the field because we are starting to see so many technologies, which have created breakthroughs in other industries, applied to the utility grid. I think we are going to see a whole lot of innovation going forward.

Industry consultant David Bassett recently retired from a 40-year career at PPL Electric Utilities, where he served as a senior staff engineer and scientist. At PPL, Bassett was responsible for large substation engineering projects and company standards and procedures for connecting non-utility generation to the system. He is Vice Chairman of the IEEE 1547.2 standard, Co-Chair of IEEE P1547.8, and an active participant in the entire IEEE 1547 series of standards.