By Kathleen Davis, associate editor
It’s been almost five years since the 2003 blackout in New York and connected regions; it’s been little more than five weeks since one rolled through parts of Florida.
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As an industry, we’ve been working on this problem since we first figured out how to set up the system and interconnect it. But, as we all become more and more dependent on power, blackouts move from nuisance to dangerous. While consumers snuggle down and generally forget once the power flickers back into play—at least, until the next outage—the question still remains: Are we making any progress in preventing blackouts and cascading outages?
To get answers, we spoke with two industry experts: David Dworzak, Edison Electric Institute’s director of reliability and Arshad Mansoor, EPRI’s vice-president of power delivery and utilization.
UAE: In your opinion, how much progress has the industry made, in the area of prevention, since the large blackout of 2003?
David Dworzak, EEI.Click here to enlarge image
David Dworzak: Two big things happened: The first was the final report on the blackout issued by the U.S.-Canada Power System Outage Task Force. Among its key recommendations was the creation of an electric reliability organization. The North American Electric Reliability Corporation (NERC) was certified as the electric reliability organization by the Federal Energy Regulatory Commission on July 20, 2006. NERC now monitors the nation’s bulk power system, assesses future adequacy, audits owners, operators, and users for preparedness, and educates and trains industry personnel. NERC and the electric power industry are also working together to test, inspect, and analyze the system’s reliability, especially relays and other kinds of system protection devices.
The second big thing was giving NERC the authority to establish mandatory reliability standards that are binding on all market participants with penalties for non-compliance. Prior to this new authority, compliance with industry reliability requirements for operating and planning the bulk-power system was voluntary.
Arshad Mansoor, EPRI.Click here to enlarge image
Arshad Mansoor: First, the industry has moved forward by following the recommendations in the NERC blackout report such as the founding of the electric reliability organization, the Transmission Owners and Operators Forum (TOOF) and adopting comprehensive operator training initiatives. Second, on the technical side the industry has, for example, the opportunity to get a more accurate view of the grid through the adoption of phasor measurement units (PMU). However, changes are not taking place as fast as they could be; one reason is a lack of consensus about how such massive amounts of real-time data can be converted into useful and actionable information for grid operators. Bringing clarity through research on how to distill and convert the data remains a challenge.
Increasing situational awareness, a strong third contributor to preventing grid outages, converts data into actionable information. Other technologies, such as advanced alarm processing, can help to get to root causes quickly. However, developing these tools is expensive and the commercial market for their application is very limited. I believe the industry and the public could do a better job of collaborating to develop and implement the solutions.
UAE: Blackouts have numerous potential sources—terrorist actions, technology failures, weather. Does each source require unique planning, funding and equipment?
Dworzak: Maybe not unique, but they all present different types of challenges: The principal measures to protect against terrorist attack are security and software. For technology, it is redundancy. The electrical grid has redundancies that should minimize serious disruptions in the event of an incident involving a power plant or transmission line.
Weather-related issues are addressed through broad system forecasting, but no one can predict which utility will get hit by a hurricane or other severe weather storm. Nor can anyone foresee precisely where the damage will be, but utilities can and do take measures to contain blackouts and get the system back up. One way is by strengthening the system’s infrastructure to improve resiliency to future storms. Another is to prepare for a storm to ensure that an organization has the appropriate training and skills to respond. And then continually test and refine the restoration plan so that is current and effective.
Mansoor: The goal is to ensure that any event does not result in a cascading blackout—for any reason.
When running the transmission network, where cascading is a potential issue, the operator follows the reliability standards—including that no single contingency can cause the system to cascade and that all reserve requirements are met. In case the reserves or contingency requirements are not met, then the operator will initiate remedial actions, shedding selected loads to bring the system back to prevent cascading outages. This action plan is common to all possible causes and sources.
Technology failures have a random element to them and the transmission system is designed and operated to function through any single failure without a blackout. The utility can’t plan for specific events but does prepare for possible events by having the parts, operational processes and expertise in place to correct the situation. In extreme weather you may have a multitude of random events. You need to be ready to deal with multiple equipment failures in a short time period.
UAE: A number of people point to aging infrastructure when there’s a blackout or cascading outage. What T&D areas remain critically behind in funding and upgrades?
Dworzak: It is hard to say whether or not any one T&D area is behind in funding. But, we see an overall need for the system to be modernized—new generating technology, new renewables, automated relays and sensors. Our sector of the industry invested $6.9 billion in the nation’s transmission infrastructure in 2006, and we plan to invest an additional $37 billion from 2007 to 2010. That is a 55 percent increase over the amount invested between 2003 and 2006. According to NERC’s 2007 Long-Term Assessment, the total number of transmission miles is projected to increase by almost nine percent over the next 10 years. This is more than a 30 percent increase from the previous assessment.
Even with this progress, building transmission faces many hurdles today. Public opposition, especially in densely populated areas, as well as differences in state statutes and regulations, have made transmission lines among the most difficult facilities to site. The lengthy permitting delays are problematic for power companies and for consumers. Besides the extra costs, the delays raise reliability concerns as well.
Mansoor: Much of the infrastructure has reached its designed life expectancy and the probability of failure is increasing. Utilities look at this question very diligently. They develop strategies to upgrade or replace the equipment that has a high probability of failure and a large impact if it does fail. In one instance it may be a transformer. It could also be a set of breakers or the upgrade of a transmission line.
Cascading is still an operational issue. We need to be able to operate the grid so that no single failure can turn into a cascading event. This is true if we have a very robust transmission grid with wide margins for both thermal and stability limits, but also for a grid that is operated close to the margins. Operator reaction time and their situational awareness capacity are essential in preventing cascading.
Not all the barriers to mitigating infrastructure issues are funding related. Over the last few years the industry has had constant load growth, but did not build additional transmission lines to meet the increased demand. Siting new transmission corridors has become more difficult than siting new power plants. The result is the system is operated closer to its thermal and stability limits. Coping with random equipment failure when operating the transmission system at its physical limits requires quick action from the operators. This may include selected and pre-planned remedial actions such as emergency outages to prevent the possibility of cascading outages.
UAE: There are a lot of technologies whose inventors and marketers claim can help prevent a blackout. In your opinion, what are the best technologies to help avoid blackouts?
Mansoor: The power grid is a highly engineered system, and there is probably not a definitive “best technology” list. There are no silver bullets to avoid blackouts. We have to apply the most appropriate and economic technology solutions to the specific issue at hand. A technology which may be inappropriate to apply to a transmission problem in a lightly populated area may be the best technology to apply in a densely populated urban area. That being said there are a handful of key technologies which support a robust grid irrespective of the scenario:
- Visualization and decision support tools for operations and planning that turn data into actionable information.
- Smart grids and communications infrastructures to enable automated response to power disturbances on the grid as well as secure integration of demand response and distributed generation and online asset monitoring.
- Robust transmission grids that include power electronics and bulk energy storage with the capacity and reliability to operate with 20 percent to 30 percent intermittent renewable resources.
For localized outages due to equipment failure, there are promising technology developments. A line of sensors are being developed and field tested that perform online asset health evaluations. We can detect the symptoms of some equipment failure modes and can flag the asset, such as a transformer, for emergency maintenance or replacement. For example, localized winding damage in a transformer can create bubbles which produce a unique sound pattern. An audio sensor with sophisticated signal analysis software can isolate this low volume sound from the 60Hz hum or the cooling fan noise. Combine this with a three-dimensional localization technique and you can determine the level of anticipated damage as well as the location within the transformer. I know of a few examples where, based on the online monitors, the transformer was taken out of service without an outage, fully inspected and then retired. In one example it was estimated that the equipment would have failed in the near future.
Increasing intermittent and demand response resources are making the grid more complex; however the industry will need to accommodate these resources in a carbon-constrained world, especially with requirements for connecting wind generation. The reliability of demand side management is another contributor to grid complexity. The grid needs to be able to accommodate these resources, which are key contributors to carbon mitigation, even if they may push grid operations closer to its limits. We have to develop and deploy storage solutions to deal with the variability, because the variability may push the grid closer to the limits of its capacity.
Great improvement in computing power and architecture will allow us in the near future to determine the dynamic stability of the transmission system online. Presently these calculations are done offline and always a few hours late.
UAE: Are there any ways that the average consumer can help their utility prevent the lights from going out? Perhaps something like demand response?
Mansoor: Yes. Resource adequacy is the heart and soul of a robust power grid. It is the balance of supply-side resources and demand-side load. We can add generation and transmission resources, and we can reduce the demand. From an operations point of view, we don’t need responses to requests for demand reduction to be precisely accurate, but we do need it to be predictable. The grid of today and tomorrow will rely on load reduction when called for, or we’ll have an imbalance between supply and demand. Such an imbalance may push the system closer to its operational limits and cut into the operating margins, reducing the robustness of the system.
Dworzak: We are encouraging customers to become more energy efficient. This helps them, and it helps the system. As an industry, we have been promoting the efficient use of electricity since the first oil embargoes of the early 1970s, and we continue to make significant progress with our efficiency programs. But, to transform our industry successfully, we need to transform energy efficiency’s role in our energy mix. Energy-efficiency must be viewed as the equivalent of generation. It must be factored into the portfolio of generation capacity that each utility holds. In order to do that, we must develop new business models that enable efficiency to become a durable and sustainable business for utilities. A number of electric companies and their state regulators have already begun this process.
New technologies will also help us to transform the role of energy efficiency in America. For example, a new “smart” grid that enables electric utilities and their customers to communicate with each other opens the door to greater savings in energy and money, as well as a variety of potential new services.
Recently, we formed the Institute for Electric Efficiency under the auspices of the Edison Foundation. This new organization will act as a forum to share energy efficiency information, ideas, and promote best practices among electric utilities. The formation of this institute further emphasizes the critical nature of energy efficiency in all we do and the commitment that our industry is making to it.
Regarding demand response (DR), research shows that demand response does work—certain consumer groups respond to dynamic pricing and DR payments in ways that can reduce electricity usage during critical periods of low capacity reserves or transmission constraints. Thus, DR can mitigate price spikes and potentially reduce the need for additional supply that would otherwise be needed to meet demand that was not price responsive. But the response from the demand side must be reliable—it must be there when we need it, just like generation.
UAE: We hear a lot about the savior qualities of superconducting technology. How much impact will advances in that area have on preventing future blackouts?
Mansoor: Superconductivity can be a great contributor. The DOE is doing a lot of research in accelerating the deployment of superconductivity technology. Today, it will allow an approximate increase in transmission and distribution power throughput by two to three times. For niche applications with very high power density and minimum real estate for additional cables, it is already economically feasible.
But with the high power density and the complexity of the cooling requirements, the industry will need to deal with different but also high-impact contingencies. The economics for implementing the technology over long distances are estimated to be out of reach for at least 10 to 15 years.
UAE: If I have a tight budget—imagining I’m a utility—what equipment and software should I upgrade first? What needs help immediately to prevent future blackout issues?
Dworzak: This will vary by utility, and, since every utility is different, there really is no one answer. The objective for every utility, however, is the same: “I must maintain reliability. How do I do it cost effectively?” Reliability is not optional.
Mansoor: Tight budgets will require addressing high-priority equipment reliability first. Today, there are mature processes and methodologies in place to prioritize the capital and maintenance expenditures to manage the investment decisions in order to take care of high-impact corridors or locations first. These methodologies put a high value on outage prevention and grid stability improvements.
Tight budgets also require you to work smarter. If it is too expensive to increase the operating margins, we need to learn to manage the grid better within its existing margins. We need to better translate the data into actionable information, both for operations but also to determine the end of life of the equipment.
Performing automated online asset health assessments using sensors and signal processing solutions may enable us to anticipate an impending failure of select assets. Anticipating the failure will allow the utility to prevent outages by replacing the asset before it actually fails. Automating this is feasible because we can leverage the investments many utilities have made in AMI technology. Of course, we need to ensure that the communications information technology in addition to AMI can support this online asset health assessment.
We also need to continue to invest in monitoring and decision-making tools to have better visualization and control of the grid.
UAE: In a fantasy budget, a limitless budget, what would you tell a utility to “splurge” on?
Dworzak: It does not come down to one item. The industry needs it all. We need generation, transmission and distribution, renewables, demand side management. We also need public policies that encourage investment in the electric power system—this includes tax incentives for smart meters and bonus depreciation on long-lived capital assets, like transmission.
On the tax front, we were disappointed that a number of provisions were dropped from the Energy Independence and Security Act of 2007, which was signed into law at the end of last year. Among them were the production tax credits and incentives in the Energy Policy Act of 2005 (EPAct 2005) that are spurring the growth of renewable energy sources. These include a long-term extension of the production tax credit for renewables, and the investment tax credit for solar. These are now set to expire at the end of December, and it is critical to investor confidence that they get extended.
We are working aggressively with Congress and a long list of allies to find a way to get these tax provisions extended in legislation this year, as well as including accelerated depreciation for smart meters, which would enable all electric utilities to depreciate smart electric meters over a five-year period.
Mansoor: The number one investment must be to overlay the existing transmission network with a backbone transmission system to greatly improve the present through put capability. There is the possibility to go to a strong transmission backbone that includes high-voltage AC and DC lines. The industry also needs to consider evaluating the positive grid stability impact of HVDC (high-voltage DC) technology.
There are some ideas that are visionary but are constrained by financial reality. One approach proposes to isolate the present grid into multiple smaller grids and reconnect them through back-to-back DC converters. The anticipated result is that the smaller grids react quicker to significant events than the large interconnected system. The back-to-back DC connection also provides a controllable barrier for a cascading effect. It still provides controlled power flow for emergency situations and for supporting regular market transactions. But the cost to implement such a system is expected to be very high.
A second investment must be into the IT infrastructure. It should be based on a foundation that will support multiple applications from transmission to end user. Data warehouses and mining applications can be a rich source of data to create information to operate the grid in a smarter and more efficient way.
The industry should deploy several suites of sensors, such as PMU, which help to determine the complete system state and an asset monitoring system to determine the health of the equipment. This would allow the industry to deal more efficiently with the complexity of the power delivery system.
But, no matter how much or how little a utility has to spend, the key is to always spend smartly.