by William Atkinson, contributing editor.
As government agencies demand utilities improve electric grid reliability and security and utilities seek performance improvements on their own, the demands utilities place on substation equipment vendors continue to grow. Utilities want better performance, reliability and security.
Vendors are responding. Some are proactively identifying next-generation products and equipment.
“We are a bit different in that we are constantly working closely with utilities to come up with solutions that aren’t necessarily mainstream,” said Jeffrey A. Howe, general manager of the power switching division at Southern States LLC.
The company’s technical advisory council works with representatives from major utilities, engineering firms and technical consulting firms.
“We look for things that aren’t done well by existing solutions,” Howe said. “From this, we develop purpose-built products that are designed for specific applications.”
Southern States, for example, introduced a capacitor switching device several years ago. Most such devices are standard circuit switchers with some add-ons to make them handle the special duty of switching capacitors better, he said.
“However, we looked at it from a different angle and came up with a device that we built from scratch specifically for capacitor switching,” he said.
Initially a few utilities used it. These days, the product is the main spec product for many utilities and wind farms.
More recently, Southern States came out with a very low-footprint, noncontact current-sensing device called CMD-II.
“Transformers can be dangerous,” Howe said. “When they fail, they can fail violently.”
Because they have sensing wires near high voltage, workers are only a few inches from very high voltage. The CMD-II has a large gap, so it keeps away from the high voltage and is much safer. It also eliminates the need for utilities to have batteries that require maintenance.
“It can also be clamped onto anything,” Howe said.
Southern States also offers a special-duty reactor switcher called the RLSwitcher.
“Capacitor switching and reactor switching are both increasingly needed in utilities with all of the NERC (North American Electric Reliability Corp.) reliability requirements and as a result of the voltage and current instabilities that can occur when adding renewable generation to the grid,” Howe said.
The result is a significant increase in demand for reactive compensation–putting in cap banks and reactors to stabilize the grid.
“We designed it specifically for reactor switching duty,” Howe said.
Reactor switching usually involves very low currents and very high voltage–the definition of lightning. The problem is that it is easy to interrupt the circuit.
“There is not enough gap to ensure that it stays interrupted, so you can end up getting reignitions, which are like lightning strikes on your multimillion-dollar reactor,” Howe said. “These also wreak havoc with your contacts inside the switcher. As a result, this device makes the reactor and the switchers last longer.”
Southern States designed a special interruptor that delays the interruption. It draws out the arc until there is a big enough gap to eliminate or enormously reduce the chance of a reignition. The device is available up to 362 kV, and Southern States soon will have it available for 500 kV.
As a way to help utilities improve substation performance, Schneider Electric offers tools for automating substations with new protocols and standards, including IEC61850, which is an entire suite of global standards that impact the life cycle of substations from design, installation and testing to end of life. There are just a few installs and investigations, however, in North America. Schneider is implementing the largest IEC61850 substation in North America.
This automation is new in the U.S., said Lance Irwin, director of Schneider’s grid automation solutions.
“It is not yet accepted well in the U.S.,” he said. “It is having a hard time overcoming the DNP3 communications protocol standard.”
The standard addresses how to do protection and other standard work.
“The tools we offer actually bring value through automating some of the processes and also address cybersecurity,” Irwin said.
Another Schneider product improves reliability. The VOX Outdoor Station Breaker is a gas-insulated solution that saves space and offers environmental protection from dust, humidity and salt, said Stacy Tamasi, staff product marketing specialist for gas-insulated switchgear at Schneider.
“The circuit breaker itself is in a sealed tank of SF6 gas, allowing for space savings,” Tamasi said.
The EOX Outdoor Station Breaker is a smaller version similar in features and functions to Schneider’s other station breakers. One EOX feature is a magnetic-actuated mechanism, instead of a spring, that increases reliability, Tamasi said.
And a Schneider relay-mitigation product designed to improve reliability covers equipment protection and personnel safety, said Ken Joye, staff product marketing specialist of engineered-to-order medium-voltage (MV) products.
“This improves reliability, performance and security of the equipment,” Joye said. “It also protects the personnel who might be in the switchyard working on the equipment, as well as the equipment itself, as a result of arc flash reduction/mitigation.”
A related product is the ArcTerminator, designed to reduce the impact of the arc by shutting down quickly.
“ArcTerminator provides total arc flash reduction, which protects personnel and equipment and thus reduces downtime since there are no catastrophic equipment failures,” Joye said.
To improve substation security, Schneider offers video security as a service (SaaS). There is a major effort by utilities to curb substation copper theft, Schneider’s Irwin said. The SaaS solutions can help utilities deploy video security quickly in remote sites.
“It allows them to deploy cameras in locations where they may not have the IT infrastructure in the back office to do digital video recording and tie into alarm systems,” Irwin said.
The cloud-based service allows fast implementation without the need for heavy communications network or information technology equipment on the back end. Users can do a live look-in, get alarms on motion with video snippets and do scheduled recordings.
PPL Corp.’s 2012 capital program is more than $660 million and almost evenly split between transmission and distribution system upgrades. It’s part of a $3.6 billion, five-year program to improve reliability and operating performance, said Michael Wood, the utility’s senior manager of corporate communications.
“As part of this program, we are building six distribution substations this year,” Wood said. “We are also building some new transmission substations.”
As for substations, PPL is focused on performance, reliability and security, said Howard Slugocki, PPL supervising engineer of distribution planning.
“Performance and reliability are paramount,” he said. “We want the best equipment we can get.”
In addition, the utility always looks for low-maintenance equipment. For example, it is switching to vacuum breakers instead of oil.
“We want to get our SAIDI (System Average Interruption Duration Index) and SAIFI (System Average Interruption Frequency Index) numbers down as low as we can,” Slugocki said.
PPL is required to meet certain Federal Energy Regulatory Commission (FERC) security standards, and these are always in mind when the utility purchases substation equipment, Slugocki said. Security is also an important component of PPL’s smart grid initiative.
“We are looking at different ways of communicating–wireless, microwave, cellular and even WiMAX–so we have to make sure that this technology is secure,” Slugocki said. “If we are going to be operating devices, especially with computers controlling things automatically, we want to be sure that no one can hack in and start opening up switches.”
When communicating with this equipment in real time, security is even more important, Slugocki said.
PPL also is upgrading its supervisory control and data acquisition (SCADA) to a more open system with DNP3 protocols. It is installing new SCADA equipment in new substations and has a five-year program to replace SCADA in nearly all of its existing substations.
“Once we have communication at the substations, we will know if a breaker is out or broken,” Slugocki said. “Today, we have to wait for the phone to ring.”
The SCADA rollout also will require security measures because of the communication features.
Southern States’ Howe said increasingly more reactive compensation is being implemented in substations to improve reliability.
“NERC has been very active in pushing reliability standards, including more need for information reporting,” he said. “Over time, I think devices are going to get smarter.”
Some substations are automated, he said, but they are centrally managed with all of the intelligence in the control house. The substations generally have dumb actuating devices.
“In the future, I think that switchers and other substation devices are going to have more and more intelligence that will allow the central control to distribute its decision-making,” Howe said.
Instead of saying, “I am going to decide when to switch on and off,” the central controller might say, “Here are the parameters. I want you to manage the voltage within this range, and you let me know when you are switching.”
Bill Atkinson is a freelance writer based in Illinois. Reach him at firstname.lastname@example.org
Utilities are trying to curb substation copper theft.
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