The Northeast Power Coordinating Council’s Regional Standards Committee last week held a forum on reliability issues related to distributed energy resources, featuring presentations by Hydro-Québec, Duke Energy, Ontario’s Independent Electricity System Operator and others. Here’s some of what we heard.

Duke Energy: Donuts and Data Sharing

Adam Guinn, lead system operations engineer for Duke Energy, gave a presentation on his work on modeling and processes to integrate DERs to support real-time monitoring and forecasting. Guinn said tighter coordination among transmission and distribution operators and planners is essential to managing the changes brought by DERs.

How does Duke do it?

“They [planners] buy me donuts,” Guinn joked.

Guinn said he has daily phone calls and in-person meetings at least quarterly with system planners, and also trades data with his counterpart who does solar studies for Duke’s planning group.

“Anything he sees he immediately sends to me, so we’re on the exactly same email chain in communication groups for any new solar, any new facility changes that may impact current solar dispatch. … We’re both tapped into the interconnection queue, and we do data analytics and tracking for growth and penetration so that we make sure that his longer-term stuff is keeping up with what we’re seeing in real time.

“We’re essentially coupled at the hip now, and that’s not just planning. It’s the same way with distribution. Distribution planners, transmission planners and operations … we’re essentially all transferring data and information and things that we’re seeing, lessons learned, back and forth in somewhat of a real-time fashion just because this stuff changes so fast.”

Guinn said having a common “knowledge base” is the key.

“What I’m finding is that all of these problems [would be] somewhat more manageable if people would stop talking past each other or stop working in silos and start transferring information,” he said. “So, if I were to wave a [magic] wand, I would get everyone on the same sheet music … and stop bringing people in who don’t have any operations experience to implement solar, to implement processes — or don’t have any planning experience.”

Task Force Guidelines for Interconnections

NextEra Energy’s Allen Schriver, chief operating officer of the North American Generator Forum (NAGF), discussed the work of NERC’s Inverter-Based Resource Performance Task Force, which is working with the Institute of Electrical and Electronics Engineers to develop the P2800 standard (Interconnection and Interoperability of Inverter-Based Resources Interconnecting with Associated Transmission Electric Power Systems).

Schriver said the task force is currently reviewing comments on its guidelines recommending improvements to interconnection agreements. The comment period closed July 24.

“What do you need to ask when you’re interconnecting inverter-based resources? … Essentially what you’re asking is: What do you want them to do? When do you want them to do it, and how fast?”

One recommendation is that DERs do not attempt to reconnect during black start events.

“If you come off during a black start, do not come back on until the [balancing authority] wants you to come back on. Do not automatically reconnect because … you may take the system back out,” Schriver said.

NERC, the NAGF and the Energy Systems Integration Group (ESIG) will hold a workshop Sept. 17-18 on storage, hybrid resources and frequency response. The workshop will be held at NERC’s D.C. office with a teleconference link to the organization’s Atlanta headquarters.

The workshop will include discussions on the capabilities of battery energy storage; motivations, drivers and challenges of hybrid projects; planning, interconnection and modeling; and ISO/RTO market rules.

Canada Adapts to DERs

The forum included presentations by several Canadian representatives.

Adnan Akhtar, supervising network management engineer for Hydro One, said his company is looking to change how it applies thermal limits on its system because more than 50% of its feeders in Ontario have less than 3 MW of generation capacity left.

“We’ve found that the non-exporting generation isn’t contributing to the thermal limit. We’re able to relax our thermal requirements to allow some more non-exporting generation to connect, at least at the feeder level,” he said, adding that the utility still must observe short circuit limits.

Akhtar said the company is implementing DER management systems to allow higher outputs. “We’ve always based our planning criteria on the worst case — minimum load, maximum generation — and that ends up leaving you underutilizing your assets for the majority of the year because your worst-case scenario probably happens maybe a few hours a year or maybe a few days a year.”

Mohab Elnashar, a senior engineer for performance validation and modeling for Ontario’s IESO, discussed the ISO’s 2019 Operability Assessment, which looked at the impact of increased penetration of inverter-based DERs on the bulk power system, with a focus on light loading conditions.

IESO has already seen instances of reduced power system responses after transmission faults. It also has identified a new single largest contingency (SLC), recognizing that under certain conditions, three-quarters of the province’s DERs could trip from a transmission fault, Elnashar said.

The loss of a single 878-MW unit at the Darlington nuclear plant has been Ontario’s SLC. “If the fault occurs at Darlington, a Darlington generator and DERs will trip, causing a new and very large SLC for Ontario,” Elnashar said.

The report found IESO has enough synchronous hydroelectric and nuclear generators to support system inertia and primary frequency response after a fault, but it recommended changing the voltage trip settings on inverter-based DERs. It is working with the Ontario Energy Board to adopt the new Canadian Standards Association rules on DER performance.

It’s also considering occasionally increasing operating reserves and seeking cost-effective transmission reinforcements that could reduce the DERs lost because of a single contingency.

“The only time we would need to increase the operating reserve is when we have light loading conditions [and] high penetration levels from the distributed energy resources,” he said. “During light loading conditions, we don’t have the gas units [to provide] voltage support in the load centers.”

Transmission planning engineer Nicolas Compas, of Hydro-Québec TransÉnergie, said that because his company’s generation is already 99% renewable, it has very few DERs and no decarbonization goals. Thus, it expects electric vehicles to be a bigger impact than solar PV generation. By 2030, it projects it may have 25% EV penetration but only 5% PV penetration.

Compas said the company tested the eight most popular inverter models to see how they react in low-voltage or low-frequency situations, how they manage ramping power, and how to change their settings. “None of them meets Hydro-Québec requirements,” he said.

“DER will grow in Hydro-Québec, that’s for sure. It will still be different from other utilities because of our weather, because of the [low] energy prices. … We have a slower adoption curve, so we can learn from many of the other utilities that already have a lot of DERs and can see issues coming up.”

SPIDER Working Group

Dan Kopin of Utility Services briefed the group on the work of NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group, which in June issued a draft reliability guideline with recommendations on developing underfrequency load shedding (UFLS) programs that can work with increasing DER penetration.

It is reviewing reliability standard MOD-032-1 to consider including DERs in interconnection-wide planning cases.

For insight on the impact on island-level system frequency as higher levels of load are served by DERs, the group has examined research by ISO-NE. It also found lessons in a September 2016 incident in which 850,000 customers in South Australia lost power after two tornadoes damaged three 275-kV transmission lines. According to a report by the Australian Energy Market Operator, the damage caused the lines to trip, resulting in six voltage dips over a two-minute period. The faults caused a drop in wind production and a surge in imported power that tripped an interconnector offline. The South Australia grid then islanded from the rest of the National Electricity Market.

“Without any substantial load shedding following the system separation, the remaining generation was much less than the connected load and unable to maintain the islanded system frequency. As a result, all supply to the [South Australia] region was lost,” the grid operator reported. It said the incident highlighted the need for more inertia to slow down the rate of change of frequency and allow automatic load shedding to stabilize the grid within a few seconds.

“The rate of change of frequency following separation (6.25 Hz/s) was too great for the UFLS scheme to operate effectively,” Kopin said.

He said he’s encouraged by the analysis that ISO-NE and others are doing on the growth of DERs. “I think it’s fair to say that all the planning coordinators involved with SPIDER are there because they get that this is a problem,” he said.