Just as intelligent electronic devices (IEDs) ushered in the era of substation automation some 15 years ago, recent breakthroughs in high-speed data collection, knowledge-based analysis and information delivery have touched off a technological revolution that is best described as “advanced substation automation.” This new technology allows utilities to automatically retrieve and process the vast amounts of untapped data they need to make decisions that directly reduce operating costs and improve T&D reliability.
Traditional substation automation gained acceptance in the utility industry by improving operational data access and enhancing control functionality. But for many utilities, this technology has fallen short of providing the direct financial return required to justify the investment. Some advancements have been made in communications infrastructure and data collection protocol standards, but until now these improvements have not addressed the areas where the greatest financial potential of substation technology lies-making use of all substation data, converting it to productive information and delivering that intelligence to the people who can apply it.
Advanced substation automation (ASA) promises to do this and more. And it’s not a theoretical application. Several projects have been implemented already throughout the United States, and other utilities-such as Riverside Public Utilities (see Sidebar, page 48)-plan to implement the technology soon.
What is Advanced Substation Automation?
The best way to describe ASA is by contrasting it with standard substation automation. In general, the term substation automation applies to the replacement of analog measurement, protection and control mechanisms in the substation with electronic devices. These instruments, which include IEDs, digital fault recorders, and power quality monitors, typically attach to feeders, breakers and transformers. In addition to providing control functionality, they feed analog status and event data back to a master station or SCADA.
This data is often referred to as “˜operational’ because it provides a snapshot of how the system is operating by taking a sampling of voltages and currents at the substation every few seconds. This lets the control center operators know the status of feeders, breakers and transformers so that load flow can be properly managed and operations can be fine-tuned. If there is a fault or transformer failure, the data tells the dispatcher what happened and where it occurred. The dispatcher knows how to respond to the immediate event and where to send a maintenance crew.
A shortcoming of this procedure is that although the real-time status and event data go to the master station, a lot of other valuable data is left behind at the substation. Usually referred to as “˜non-operational,’ this data includes historical fault records, current and voltage waveforms, performance records of other equipment during faults, lightning strikes and breaker operations.
While the operational data tells the operations center what happened, non-operational data can often reveal why the event happened. The best example of this is the electronic protective relay. It notifies the control center when a fault occurs, and it also records the waveform of the current before the fault. Proper analysis of this waveform and its associated digital events can reveal the type of fault, why it happened, and whether it was cleared properly. If this information were available to the dispatcher, he or she would know when and how the fault could be cleared remotely and when a field crew was needed to repair malfunctioning equipment.
Advanced substation automation, therefore, picks up where regular substation automation falls short. ASA collects all data, both operational and non-operational, from all digital devices in the substation, regardless of device protocol, data format or file size. There are enormous volumes of this data in the substation, more than could be analyzed by manual methods. This is why intelligent analysis processes must be utilized.
ASA, therefore, includes analysis modules that integrate, correlate and analyze the data sets, looking for events requiring engineering attention. Finally, the ASA system creates customized reports on system performance and utilizes web-based server technology to deliver them to key personnel who can use the information to make-in some cases-real-time operating decisions that positively impact the bottom line.
Customized reports are a necessity because every department in the utility looks at the system differently. Maintenance, operations, protection and power quality/reliability personnel each view events from varying perspectives, and therefore, need information tailored to their particular view. Analyzing data, deriving information from it and then presenting that information correctly to the right personnel when they need it are the focus of ASA.
The Evolution of ASA
ASA sounds simple, but it actually required several technological breakthroughs to become reality, which is why a practical ASA solution has only recently been introduced. The first obstacle was data access. Non-operational data can be downloaded from IEDs only using vendor-specific protocols. Although standards are being developed, a library of device-specific drivers had to be developed and continues to be expanded to retrieve the complex data stored in the substation IED and apparatus-monitoring devices, which is a critical aspect of advanced automation.
The sheer difficulty of automating the analysis of multiple data sets-essentially mimicking human reasoning-has been a major stumbling block to ASA development. Knowledge-based systems including neural networks and embedded expert reasoning have been leveraged to sift through the data and extract only those files required for analysis. These intelligent systems then look for relationships between events, such as a fault and lightning strike, to determine which pre-established set of responses should be suggested to the operator.
An emerging science in the power industry, called intelligent systems, which includes adaptive fuzzy systems, has been incorporated into ASA technology to allow the system to teach itself. For instance, one ongoing study is examining the use of ASA software to predict transformer failures. Regularly evaluating transformer gases and the impact of faults, loading and environmental conditions can determine the likelihood of an approaching failure.
The final hindrance to non-operational data use has been solved by advances made outside the utility industry. This obstacle was efficient data transmission and storage. Non-operational data files are huge and usually can’t be transferred over phone lines. Fortunately, a growing number of utilities, including Riverside Public Utilities, have installed centralized fiber optic networks connecting their substations for high-speed data transmission. And, increasingly common and less expensive today are databases capable of archiving large volumes of data in a variety of file formats.
Why Advanced Substation Automation?
Utilities are trying to squeeze extra life and higher capacity out of aging equipment, and they are attempting to do this with ever-shrinking staffs. Dealing with these universal challenges is why so many invest in substation automation. While ordinary automation does help fine-tune operations and restore outage quickly, the return on investment is often not as great as the utility expects.
Once again, this is where ASA differs from and supplements regular substation automation. Rather than simply notify the dispatcher that a transformer has tripped, ASA diagnoses the problem and recommends a repair that can prevent the total loss of a $1 million piece of equipment. Rather than quietly recording a line fault, ASA identifies a possible trend and suggests a repair before a complete failure puts a neighborhood in the dark.
Perhaps even more importantly, ASA takes a step beyond helping a utility deal with its universal challenges. ASA software can be configured to manage the specific issues that are causing a utility its greatest financial pain without losing sight of the big picture. Here are just a few of the diverse, yet valuable, ways that utilities are, or will soon, deploy ASA:
- Riverside Public Utilities operates aging transformers and spends a lot of time and money sending crews to perform manual analysis of dissolved gases. RPU plans to program its ASA software to retrieve daily dissolved gas analysis reports and compare them with power waveforms to determine how power fluctuations are impacting transformer health. Preventative maintenance will be scheduled accordingly.
- A utility with extensive underground feeders and a history of water seepage is carefully monitoring faults to ascertain when feeder performance is deteriorating. Rather than risk a complete failure and outage, they are replacing feeders exhibiting abnormal fault patterns.
- A utility in a lightning-prone area spends millions dispatching field crews to inspect transformers after suspected strikes and determine whether damage was done. This utility now uses ASA to correlate transformer trips with lightning strikes from a commercially accessible database. Once a strike is confirmed, ASA assesses transformer health and notifies the dispatcher immediately if the transformer can be restored remotely without damaging the equipment.
These are the kinds of applications that eliminate the specific pain points and provide immediate costs savings in terms of avoided outages, longer equipment life, and more efficient use of field personnel. ASA performs these customized solutions focusing on specific equipment while it continues to monitor the health of every other subsystem in the transmission and distribution network.
The payoff of advanced substation automation is potentially huge compared to the hardware investment typically associated with ordinary automation. On average, ASA adds 25 percent to 30 percent to the cost of an automation implementation. Aside from the software purchase, much of this investment pays for the hiring of outside consultants to help the utility identify its pain points and pinpoint the data required to make them disappear.
Facing the Challenges
Nobody would dispute that the automated collection, correlation and analysis of non-operational data offer tremendous value to a utility, but industry-wide acceptance of advanced substation automation will still be a challenge. After all, the industry took a while before accepting regular substation automation. The challenge for the utility to make ASA work is to ask every department to identify their pain points. This may seem daunting, but with the help of an outside consultant, many utilities find their personnel are happy to sit down and pinpoint the individual problems that can be solved in their department with ASA to the benefit of the entire T&D operation.
The universal problems of shrinking staffs and aging equipment will not go away by themselves. Utilities will have to constantly find new ways to address these issues. And the best option right now is the technology that can extract usable data from the substation, analyze it automatically and provide customized reports to every level of the enterprise.
ASA provides utility executives with the rare ability to take a step back and examine the network as a whole. This is an invaluable capability in the current industry environment where executives face ever-daunting risk management decisions, constantly increasing personal accountability, and the pressures of keeping up with new technologies.
The Advanced Substation Automation Difference
Advanced substation automation (ASA) offers many advantages over ordinary substation automation. Unique characteristics and capabilities of ASA include:
- providing an enterprise-wide view of T&D system health
- automated retrieval of all data from the substation
- correlating and analyzing data for extraction of information
- getting information into the hands of individuals who need it, when they need it
- supporting enhanced SCADA and EMS technology now under development
- customized solutions to eliminate financial pain points
- achieving a quantifiable return on investment
Riverside Plans Advanced Substation Automation
At first glance, the project now getting under way at Riverside Public Utilities (RPU) appears to be just another ordinary substation automation project involving standard equipment and typical goals. But when the next proposed phase of automation begins, perhaps as early as next year, RPU expects there will be nothing ordinary or typical about it.
RPU serves the City of Riverside, Calif., and operates a network of 13 substations. Automation of these facilities to date has been normal for a utility of this size. All of its substations have remote terminal units (RTU), and several substation additions and upgrades included protective relays in the form of intelligent electronic devices (IED) in 1990. In fall 2004, RPU awarded a contract to further automate the several substations.
“We need a more efficient mechanism to get operations information to our dispatchers and engineers, and one that’s friendly to configure and maintain,” said Joseph Carrasco, senior electrical engineer at RPU.
The project calls for providing one new substation with protection, digital fault recording, and control IEDs and adding electronic protective relays at three others. In addition, the utility plans to install a new supervisory control and data acquisition (SCADA) system. All existing RTUs will be upgraded to communicate with the new SCADA. The current serial communications network will also be replaced with a local area network (LAN) that will make it much easier to retrieve and share information from the IEDs to RTU and to SCADA, and from IED to IED.
“With improved information the dispatchers will be able to better respond to outages and operate the transmission and distribution system more efficiently,” said Carrasco. “And our engineers and operations personnel will get the data from equipment to more efficiently analyze the system and maintain it.”
Despite these benefits, Carrasco says there is potential to accomplish much more with the automation. As he sees it, one of the drawbacks inherent in automation is that engineers and technicians still have to travel to the substation to retrieve data or download it through a slow dial-up connection. The data must then be analyzed manually to figure out what the root cause of a fault or outage was. Data collection and analysis can take several weeks and additional damage or failures can occur in the meantime.
This is where the second phase of the RPU automation project will differ significantly from most others. In its next round of capital improvements, the utility expects to earmark funds for what is best described as “advanced” substation automation. This will involve installing new software technology designed to automatically retrieve data from the substations, analyze it, and deliver response recommendations to the appropriate dispatchers, engineers and maintenance personnel.
“When I heard about this technology, I knew it was a big time saver,” said Carrasco. “Our utility has limited manpower, and anything that provides a faster, easier way to present information to the right people at the right time is a huge benefit.”
When RPU gets funding approval to move ahead with its proposed project, it will join the small, but growing, number of T&D utilities that have deployed advanced technology to enhance the returns on investment already made in substation automation.