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IEEE: The expertise to make smart grid a reality

Interview with Jay Giri

Jay Giri has been named an IEEE Fellow in recognition of his contribution to advances in Energy Management Systems (EMS) technology.  He is also the director of Power Systems Technology and Strategic Initiatives at ALSTOM Grid.

In this interview, Jay Giri discusses recent advances in energy management technology with an emphasis on synchrophasors and their application to a range of service reliability and operating efficiency issues.

Question: The Smart Grid's value in energy conservation is well publicized but electric utilities also expect the Smart Grid to enhance service reliability. Can we look forward to the Smart Grid eliminating blackouts, for example?

The electricity grid is too complex to eliminate blackouts completely. Deployment of Smart Grid technology will enable enhanced system monitoring, advanced measurement and control technologies, and innovative analytics to help reduce the number of blackouts or help contain a local blackout from becoming a widespread system outage. The 2003 blackout on the East Coast was estimated to cost the U.S. economy $6 to $8 billion. Preventing losses like that justifies increased new investment in emerging technologies such as synchrophasors.

Question: What are synchrophasors?

Synchrophasors are fast sub-second rate power system measurements such as three-phase voltages and currents, frequency, and rate of change of frequency. These measurements are time-stamped to a common global time reference. This provides synchronized real-time monitoring of multiple remote points on the electrical grid and also provides monitoring of fast dynamic grid behavior.

Synchrophasors are measured by Phasor Measurement Units (PMUs). A PMU can be a dedicated device, a meter, or any measuring device that can accept a global time reference and properly time-stamp the power system measurements. A single PMU device typically provides 12-16 synchrophasor measurements.

Question: What benefits do synchrophasors offer that utilities lack now?

Since the 1970s, system operators have relied primarily on SCADA (Supervisory Control and Data Acquisition) measurements to monitor the grid. These measurements are asynchronous and are typically updated every 2-4 seconds. Corrective action is predicated on intelligent analysis of the SCADA data and human intervention. This is an inherently slow decision-making process. Since many of the disturbance phenomena we are trying to protect against on the grid are very fast, we need fast measurements and fast controls that do not require operator intervention.

The only Smart Grid application in use today that I feel is close to meeting these criteria is Automatic Generation Control (AGC). AGC automatically implements generation adjustments in real-time in order to maintain nominal system frequency – it is a ‘slow’ subset of the automatic closed-loop control that we’re talking about.

Question: How will synchrophasors be employed to change today's grid monitoring performance?

Because synchrophasors provide an instantaneous synchronized view of the grid’s state, we can identify and locate abnormal behaviors more quickly. They also monitor the fast dynamic behavior of the grid. For the first time in history, the control center has a snapshot of the grid with fast sub-second measurements that are synchronized. This allows for introduction of a new generation of innovative Energy Management System (EMS) software to analyze abnormal as well as dynamic behavior and to take corrective action (if required) automatically without operator intervention.

Question: How will this new, automated-response technology be implemented?

Let me address the issue of decision making in the control room first. In today’s control room, operators typically initiate emergency decision-making only after a disturbance occurs. They then need time to assimilate and analyze the disturbance information to then decide on the action to be implemented; this is time lost, during which a minor event could grow and cascade into becoming a more serious major event.

An important goal in the Department of Energy's (DoE) Smart Grid initiatives is to understand how to make synchrophasor measurements trustworthy for actionable decision-making. Once we understand that, we can deploy smart decision automation more confidently. In the meantime, thanks to several DoE-funded Smart Grid Investment Grant (SGIG) synchrophasor projects that total over $300 million, the number of PMUs in North America will grow from about 200 to over 1,000 – remember that each PMU provides 12-16 synchrophasor measurements. We will learn significantly more about benefits of synchrophasors once these PMUs are fully operational. This experience will help us design and implement smart automated control schemes to protect the grid both locally and interconnection-wide.

Question: Once an electric utility deploys synchrophasor technology, will it be able to share that information with its neighboring utilities?

Yes, subject to mutual confidentiality protection agreements. NERC (North American Electric Reliability Corporation) and NASPI (North American Synchrophasor Initiative) support the development of a country-wide 'NASPInet' communications network to facilitate sharing of PMU data. It is important to provide a wide area view of what's happening on the entire grid to all transmission owners in the grid. A key benefit is the ability to promptly locate a grid disturbance in a neighboring system that might impact your operations and that is not visible or detectable in your own EMS SCADA.

A related issue is islanding, which happens when one part of the grid becomes isolated from the rest and starts to operate independently and might cause problems when it reconnects. Today, the only way an operator can detect islanding is to see a sudden change in overall interconnection frequency and to call neighboring system operators to learn more about what happened and where. Once synchrophasors are deployed, an operator at PG&E in San Francisco, for example, could immediately see that a neighboring system is operating at a different frequency, or with a different voltage-angle — both indications that the neighboring system is operating out of synchronism. This would expedite a joint discovery and decision-making process to take action, to possibly avert a major cascading blackout.

Question: Are there additional benefits to synchrophasors and PMUs?

Something we cannot do in the EMS today is grid oscillation monitoring. The new generation of EMS technologies will remedy that. Oscillations are continually happening on the grid and fortunately most of them simply disappear over time. The ones we care about the most are those that are not 'damped', meaning they do not disappear gradually over time and hence corrective action is needed to mitigate their impact on the grid. Today, grid oscillations are essentially invisible to control room operators. With the introduction of synchrophasor applications we will be able to monitor and observe them. This further enhances operator situational awareness.

There will also be EMS applications that advise operators on how to fix oscillations with corrective actions such as re-allocation of generation and switching reactive resources such as capacitors. Operators want to fix problems, not just observe them!

Question: Avoiding blackouts and similar events is important, but will synchrophasors be of any benefit in what might be called day-to-day operations?

Yes. Utilities will be able to do a much better job of maximizing the utilization of their existing transmission assets. They will be able to use synchrophasor measurements to improve the models on which their EMS tools are built. This will result in more accurate evaluation of transmission congestion as well as more aggressive, confident decision making.

Here's an example. Many 500 KV transmission systems have restrictive congestion operational limits that are designed to protect the grid in the event of a disturbance. The operator manually enters these limits in the EMS in order to ensure load on the lines do not violate the congestion limit; these limits are not changed very often and hence need a built-in safety factor to accommodate the diverse varying system conditions that occur throughout the day.

Having time-stamped, real-time data about the grid will allow us to relax the safety factor and operate the system closer to the real limit by intelligently changing this limit dynamically, during the course of the day, based on analysis of current system conditions.

Operating this way has the additional benefit of avoiding new transmission line construction just to meet an unrealistically high, pessimistic safety margin. It is very expensive to put in a new line. It is also very time consuming, because transmission lines traverse hundreds of miles and rights-of-way have to be established and neighbors very often object.

Question: This sounds very optimistic. What potential obstacles is the industry likely to encounter?

The first has to do with the age of the North American grid. The average transformer is 40 years old, and in some cases they are over 50 years old; this is close to exceeding their manufacturer’s life expectancy. Furthermore, mandates to increase deployment of renewable energy resources will introduce more variability in energy supply and consequential inadvertent stress on the grid. Some of the protection schemes that we have for local protection may not work reliably. Hence the grid is intrinsically getting less reliable and less secure.

The second and more critical challenge is communication. It's fine to have all of these synchronized measurements coming in at high data rates. But how do we make sure that the communication is secure, reliable, and cannot be tampered with, or hacked? We will be making rapid decisions based on measurements arriving at a very fast rate and we have to make them totally trustworthy. With these advanced information superhighways comes the need for enhanced cyber security plans, comprehensive monitoring of communications traffic, and strategies to ensure reliable and secure data transport.

A third obstacle is standardization. In order to have a successful Smart Grid, products from different vendors have to work together. Standards are necessary for interoperability and the development of standards is a key to assuring that all components in a utility’s Smart Grid work together in harmony.

Question: What do you envision when you look at the Smart Grid 5 to 10 years down the road?

We have not seen such a 'revolution' in our industry in decades.

Over the next 5- to 10-years, I see the promises of new technologies becoming a reality. The Holy Grail of Smart Grid is not just to visualize and monitor but also to control the grid - and that is going to only happen after this initial four- or five-year phase of building confidence with PMU measurements and synchrophasor technology.

As director of Power Systems Technology and Strategic Initiatives at ALSTOM Grid, Jay Giri also leads an engineering team that delivers synchrophasor applications to control centers.