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Real-time contingency analysis to improve grid awareness, reliability, coordination

​By Lisa Meiman

Electricity follows the path of least resistance – and every other available path.

Energy does not acknowledge utility boundaries or capacity agreements. Voltage support and the vital 60 Hertz frequency are of no concern to mere electrons. An outage is not an inconvenience but a detour.

The responsibility for achieving balance, voltage and reliability falls to dozens of power dispatch centers across the country, including four at Western. Now, their job of monitoring and wrangling electricity through the grid is changing to better understand and mitigate the system’s predictable unpredictability.

“Reliability is second only to safety at Western,” said Administrator and CEO Mark Gabriel. “Ensuring the safe, secure and reliable operations of the grid at reasonable cost continues to be a main priority.” 

The North American Electric Reliability Corporation is revising transmission operator reliability standards to require real-time contingency analysis every 30 minutes. Specifically, transmission operators will need to analyze current system conditions every half hour, identify every possible contingency and create mitigation plans.

The goal is to create a more reliable grid by improving situational awareness and contingency planning for transmission providers and reliability coordinators so they are prepared for a worst-case scenario in real-time conditions.

“Contingency analysis isn’t new,” said Upper Great Plains Transmission System Planning Manager Gayle Nansel. “We run current-day, day-ahead, peak and seasonal contingency analysis and provide 24/7 on-call support. Doing it in real-time is another story.  To do that we will need more people.

The real-time picture will allow flexibility and optimal use of the transmission system. “We are required to operate to the most constrained limits that don’t always reflect the real-time flow environment,” said Rocky Mountain, Desert Southwest and Colorado River Storage Project Management Center Vice President of Operations Darren Buck. “Going real-time will allow Western to fully utilize our transmission system and ultimately reduce the curtailment, outage and financial burden issues we see today in the day-ahead study process.”

Finally, Western dispatchers are predicting improved communication and coordination by having contingency analysis co-located with the people who have to respond to contingencies at a moment’s notice. “The operational engineers and Dispatch interact closely with this new model. Dispatchers depend on planning,” said UGP Transmission Operations and Switching Manager Mick Kirwan. “If something happens, like a disturbance or event, instead of Dispatch calling engineers for support, the two groups will be in the same room. The engineers will already be running studies of worst-case scenarios. It’s really going to be better for reliability and grid operations.”

Depending on when the Federal Energy Regulatory Commission approves the standard, the new requirement will become enforceable in 12-18 months, likely sometime in 2016. “The revision isn’t required yet,” said Kirwan, “but we need to get ahead of it.” Western’s two-year budget cycle means new positions requested this year will be available in Fiscal Year 2017.

Different circumstances, different response 

As usual, NERC leaves execution of the revision mostly up to the utilities, recognizing that transmission operators differ in size, scope and complexity. Western has the same attitude. As all regions are different in terms of size and responsibilities, Western is considering different solutions commensurate with each region’s needs. 

For the most part, the solution is a new 24/7 real-time desk located in dispatch centers and staffed with new operational engineers.  

“Engineers do the job now,” said Nansel. “Engineers are more familiar with the modeling and planning tool that we plan to use, but there will still be a large learning curve to do things in real time.” 

The engineers will need to maintain operational awareness, create supporting operation guides, understand the system, run analysis and, most importantly, know how to mitigate all kinds of contingencies. Then, the results need to be coordinated with the dispatchers in the control room and potentially with neighbors and the reliability coordinator. 

UGP Power Operations and the combined DSW, RM and CRSP MC Power Operations groups plan to go this route, hiring five to six new staff in UGP and the combined center to operate the new desk. 

“UGP is the transmission operator for the vast majority of its territory. We conduct these responsibilities for our customers,” said Nansel. Five to six people would be able to run a new desk 24/7 comfortably and account for vacation and sick time as well as training requirements. 

The joint RM/DSW/CRSP MC footprint is just as massive and complex as UGP’s single footprint, totaling about 8,000 miles, even though customers and neighboring utilities will have their own real-time contingency analysis solutions, unlike in UGP. Arizona Public Service is the closest in comparison with the combined footprint in terms of load, generation and miles of transmission, except Western’s joint footprint is three times larger, has more balancing authority touch points and nearly double the qualified paths to monitor.   

Sierra Nevada is smallest, but its complexity in the California market still qualify it for real-time monitoring. SN’s Power Operations group plan to assign the monitoring to the existing Transmission and System Operations desk in Dispatch. A new desk will run five days a week during the daytime hours. During nights and weekends, existing Dispatch staff will support the real-time contingency analysis. “We will be hiring two additional dispatchers, but we are still just talking about it,” said SN Supervisory Power System Dispatcher Carl Dobbs. A new operations engineer and supervisory control and data acquisition specialist will also help meet the requirements. 

The regions’ plans are still in the works, and Western is still discussing the new requirements with customers. “Generally, the operations divisions of the large entities are in agreement that real-time, flow-based monitoring is necessary,” said Buck.

Page Last Updated: 9/17/2015 8:04 AM