A 2019 outage event in the United Kingdom highlights the need for both comprehensive underfrequency load shedding (UFLS) protection and an understanding of the impact of a “rapidly changing portfolio” of generation resources on reliability of the electric grid, according to a “lessons learned” notice from NERC.

The incident began Aug. 9, 2019, with a lightning strike on a 400-kV transmission line north of London that caused a single-phase-to-ground fault. The fault was detected and isolated, and the line was reclosed within 20 seconds. During that time, a steam turbine at the combined cycle plant in nearby Little Barford tripped offline, removing 244 MW of generation from the grid. At the same time, the Hornsea offshore wind farm, operated by Danish energy company Ørsted A/S, unexpectedly reduced output from 799 MW to 62 MW.

After grid control systems reduced generator output — including 150 MW of distributed energy resources (DER) as part of the rate of change of frequency (ROCOF) scheme, an additional 350 MW of DERs tripped offline, resulting in a cumulative loss of nearly 1,500 MW of generation within one second of the fault. Within 58 seconds, frequency had declined from the European standard of 50 Hz to 49.1 Hz.

After another 33 seconds, as frequency was recovering to 49.2 Hz, a combustion turbine at the Little Barford plant — generating 210 MW — tripped offline, causing another frequency decline. As grid frequency passed below 49 Hz, more DERs tripped, and then operators at Little Barford took a second 187-MW combustion turbine offline. By this point, the cumulative generation loss stood at 1,878 MW and frequency had declined to 48.8 Hz, triggering UFLS schemes that disconnected 931 MW of load. This allowed the frequency to stabilize and begin to recover.

Poor Understanding of Weak Conditions

Post-event analysis found a number of issues with the performance of both Ørsted and local grid operator RWE. One of the most important was “limitations in [RWE’s] knowledge” of the Hornsea plant’s control system and “the interaction between its onshore and offshore arrangements,” which caused the loss of 727 MW of generation.

At the time of the transmission line fault, the wind farm was operating in a “weak” system condition due to a number of transmission facility outages already in progress. In addition, one of the undersea cables between the wind farm and land was out of service. As a result, when the voltage control algorithm called for increased output due to the line fault, an oscillation began that led to the overcurrent protection system intervening to reduce output.

The second major contributor to the outage was the Little Barford combined cycle plant, which accounted for more than 640 MW of lost generation capacity. Three issues led to the plant’s shutdown. First, the steam turbine went offline during the initial fault due to a speed sensor input error. The combustion turbine subsequently tripped off after a problem with the steam bypass system led to a buildup of steam pressure, which led operators to take the second combustion turbine offline about 27 seconds later. The cause of the initial speed sensor input error has yet to be determined, but the steam bypass system has since been repaired.

The last significant loss of generation — about 500 MW — came from the shutdown of multiple DERs. Although the initial 150-MW loss was part of normal phase shift protection procedure, the additional 350 MW was unexpected. Investigators determined that some of these DERs tripped offline due to incorrect ROCOF settings, while others were found to have had their UFLS triggered at 48.9 Hz instead of the correct setting of 47 Hz.

Study Needed on Behavior of Renewables, DERs

Corrective actions recommended by RWE in the aftermath of the event included reviewing its operational criteria to “determine whether it would be appropriate to provide for higher levels of resilience in the electric system,” along with reviewing the time scale for anti-islanding protection to “reduce the risk of inadvertent tripping and disconnection of embedded generation.” The utility also recommended an industry-wide review, involving regulators, utilities and other stakeholders to establish communication protocols for future events.

NERC’s analysis focused on the implications of the widespread adoption of renewable energy and DERs on grid reliability, in particular their “increasingly complex controls” that make it difficult to “predict resource responses to network faults.” The organization noted several potential flaws in RWE and Ørsted’s procedures:

• Overreliance on self-certification of the models for generating resources, including DERs;
• Insufficient understanding and coordination of the interactions between onshore and offshore wind generation control systems, particularly the performance of wind farms in weak system conditions;
• Inadequate coordination between transmission planners, generation and transmission owners, reliability coordinators and equipment manufacturers to accurately model their connected resources;
• Outdated tools, techniques and simulation approaches to planning and operations, particularly related to weak grid conditions and inverter-based resources; and
• Inadequate understanding of the impact of tripping multiple DERs on grid reliability.

To illustrate one approach to modeling DERs, NERC cited PJM’s use of publicly available data, from sources such as the Energy Information Agency and its own Generator Attribute Tracking System, combined with data requested from transmission owners. The RTO uses this information to generate behind-the-meter solar forecasts that are factored into its load forecast and to notify TOs of generation resources that may be available to help with a transmission emergency.

NERC has noted concern on several occasions about utilities’ understanding of DERs and the ability to properly account for them in their system modeling. Earlier this year, a survey by the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group found that most entities reported they do not incorporate DERs in their modeling, citing lack of data or tools or a belief that the impact of DERs is too small to account for. (See DER Modeling Survey Indicates Persistent Gaps.)

In addition, Thomas Bialek, the chief engineer for San Diego Gas & Electric, warned in January that the behavior of residential rooftop solar panel users is often very different than that expected by system planners. This creates “hidden loads” that can’t be accounted for in planning, he said. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)