WECC on Tuesday gathered leaders from the Western Interconnection’s four reliability coordinators to ask the question: What keeps you up at night?

Their responses featured as the technical session for WECC’s quarterly series of Board of Directors meetings, held virtually March 16-17 for the fourth time since the outbreak of COVID-19 pandemic.

“What’s keeping us up at night in Alberta? I can start with frequency issues,” said Lane Belsher, director of grid and market operations at the Alberta Electric System Operator (AESO).

Belsher explained that Alberta islands from the rest of the Western Interconnection about 10 to 15 times a year when its 700-MW tie line with British Columbia trips offline. In the past, islanding rarely resulted in under-frequency load shedding in the province, but two events since last June have defied that expectation.

AESO runs a program called “load-shed service for import,” in which the grid operator contracts with loads that will instantaneously trip when system frequency drops to 59.5 Hz in order to avoid wider load shedding.

“What happened back on June 7 was an eye-opener, when we thought we had enough under-frequency load armed for that, and we lost the tie line and we went into under-frequency load shedding,” Belsher said.

In the wake of the event, Belsher said, AESO produced “a major amount of studies” and implemented inertia monitoring for its operators.

“And here we go again on a Sunday in late February where we lost the tie line again,” Belsher said. “And that time, since we always seem to be running the edge, we lost just a small generator with the tie line trip — not sure why that occurred — but that generator going off [with] about 85 MW along with the tie-line trip put us into under-frequency load shedding again.

“That definitely raises flags with the government and everyone here in Alberta and gets people wondering what’s going on with our system these days and what are we studying,” he said.

Belsher pointed to the increased renewable buildout and coal-to-gas conversions occurring in Alberta, saying the frequency response of generation and load “just doesn’t seem to be where it’s been in the past.”

“It’s really raised a red flag in Alberta that, now every time that tie line trips between us and our neighbors to the west in BC, I kind of hang from my fingernails and hope we don’t load shed here,” he said.

Knowledge Transfer

Asher Steed, manager of provincial reliability coordination operations at BC Hydro, said there are three things on his mind.

The first has to do with the growing complexity of the grid as new types of resources come on board.

“The natural pace of change as well as the human change we put on ourselves is making more complexity, so I think that shows up in lots of different ways,” Steed said.

Steed’s second concern focused on the risks that occur within the changing system.

“For our system, there are certainties: We’re going to have a wildfire season,” Steed said, noting that this year’s began March 1 in British Columbia. “But what we don’t know is where exactly it’s going to impact us, if it’s going to impact the power system this year. So that’s the uncertainty we deal with from year to year, month to month.”

And given its geographic diversity, British Columbia sees extreme weather every year, Steed said: “But where’s it going to show up?”

Steed cited the situation in neighboring Alberta as another uncertainty. “We expect to see islanding events every year. We don’t know exactly how they’re going to happen. Sometimes they are coupled with things like planned outages,” he said.

The third issue on Steed’s mind had to do with his staff — and “really supporting everyone in terms of having constant readiness for the operating environment we’re working in.”

He said the “very dedicated personnel” in operations planning roles can “settle into one organization or one role for many decades.”

“As those people gain knowledge and experience, how can we learn from them?” Steed said, noting a wave of retirements in the field. “Training the next generation, having sufficient knowledge transfer, especially when we know the pace of change, is significant.”

Dealing with Ambiguity

“What keeps me up at night lately has been [that] it seems there’s ambiguity around the expectations for managing reserves these days,” said Tim Beach, director of reliability coordination at RC West.

Beach said there are “two camps” among balancing authorities on the issue. One thinks reserves should be dispatched to cover load in an emergency, with firm load only shed on contingency. The other believes a portion of spin reserves — traditionally about 50% — should be maintained to respond to a potentially critical event on the system.

“There’s ambiguity around that,” Beach said.

He said a recent survey RC West circulated among its member BAs asked the question: “What is your expectation? What is your philosophy?”

Recent events in ERCOT and SPP demonstrated the importance of those questions, according to Beach. When a February cold snap resulted in severe generation shortages in the lower Great Plains and Texas, both BAs dispatched reserves to cover load.

“I’m not sure [about] the durations of those [dispatches], but they were reserve-deficient,” Beach said.

Beach thinks that the Western Interconnection can handle a deficiency in one BA because there’s enough frequency response capability in the system to cover the shortfall. “But not if you have four or five in a certain region of the Western Interconnection, and one of those is your largest BA — California, which really dwarfs everybody else,” he said.

Beach posed the scenario of CAISO operating without sufficient reserves, then losing a nuclear plant like Diablo Canyon on California’s Central Coast or both Palo Verde nuclear units in Arizona — or facing the trip of a DC tie.

“Do we have the frequency response in the system to recover from that and arrest the frequency decline before we get into large-scale under-frequency load shedding?” he said.

“Those are the things we talk about quite often here at RC West,” Beach said. “I know the California ISO BA is also talking about it. They’ve always been under the philosophy to maintain spin. As the largest BA, that’s great, but there’s pressures to make sure you’re serving your load. And if you don’t have to shed load, should you?”

‘Wide-area View’

“Thankfully, I’m getting more sleep right now than a month ago, but I can assure you that every megawatt of load shed will be answered for,” SPP Director of System Operations C.J. Brown said, referring to the February winter event.

Brown said he likes to say: “Just because you have a bad day doesn’t mean you get to stop being a balancing authority.”

“So, to Tim’s point, you still have to maintain some level of balancing now. Where that level is is difficult” to determine, he said.

If a BA sheds more load than the public believes is necessary, it will be forced to defend that decision, he said. “It’s a tough position for BAs and RCs.” But the RC’s role is to take a “wide-area view.”

“Any issue’s a big deal. I don’t mean to minimize a local [transmission operator] issue, because they’re important and have to be addressed. But ultimately the RC’s responsibility is to make sure that cascading impact doesn’t occur,” he said.

Keeping Brown up at night are the issues of system complexity and resource adequacy.

“This whole idea of resource adequacy: What does that look like? What does it look like under the complexities? And I know that’s a big buzzword in the industry now,” Brown said.

He pointed out that SPP routinely studies for peak loads, showing 20% excess capacity in the summer and nearly 30% in the winter.

“Well, how in the world can you have an event like Feb. 15 with that kind of capacity? There’s reasons, and all that stuff is kind of coming out in the public,” Brown said.

He noted that system behavior in each area varies depending on the type of generation in operation.

“At the end of the day, the grid is different, and it’s going to act different, and we have tools and we study that. We have online stability tools we use in real time, and we do the best we can. But at some point, we’re forced to be reactionary way more than we’re comfortable with.”