The Federal Energy Regulatory Commission (FERC) has issued a proposed rule to standardize the business practices of open-access
natural gas pipelines (Docket No. RM96-1-000). The rule would...
analysis, based on representative transmission grid data available from FERC filings, incorporated many of the line and generator outages that took place on Aug. 14. The system represented includes the greater part of the Eastern Interconnection and is made up of approximately 5,000 buses and 6,500 transmission lines, of which 2,500 are monitored. Table 1 summarizes characteristics of the modeled system.
To perform the simulations, we used LCG Consulting's proprietary model, UPLAN-NPM, 1 which integrates a detailed representation of generating resources, demand, and the transmission network. UPLAN models contingencies accurately and has a rich structure to capture all the elements of day-ahead market that allocate resources for energy, synchronized reserve, standby reserve, and capacities across the entire network. We also modeled the dispatch of the allocated resources using an optimal power flow.
Simulations With Flexible Operating Reserves to Avoid Cascading Outages
The sequence of eight scenarios described in Table 2 represents the cascading events that took place between 1:30 p.m. and 4:10 p.m., on Aug. 14. 2 The scenarios reflect escalating line and generator outages preceding the blackout itself, and they include the results relating to the last two scenarios of failures that ultimately led to the blackout. For instance, Scenario 8 event is equivalent to a full-scale Aug. 14 event.
For the sake of simplicity, we focus on two of these scenarios (Nos. seven and eight). For those two cases, we describe the results that would have followed (how much loss of load, how much incremental cost to duplicate the lost production and deliver power to consumers, etc.) if, at the time of the events of Aug. 14, the grid operators in the Midwest and the Eastern Interconnect had had at their disposal any one or more of three different hypothetical sets of synchronized generation reserves and contingency plans, or lack thereof. To make the comparisons relevant, we assumed certain costs for operating this system, by estimating the costs for the region covering the Midwest, New York, Ontario, and PJM.
These results, shown in Table 3, clearly indicate that increases in the availability of synchronized operating reserves reduce the amount of unserved energy. For scenario 7, raising the synchronized reserve requirement from 0 to 3.5 percent reduces the level of unserved energy by more than 7.7 GWh (22 percent), and raising the requirement further to 7 percent lowers unserved energy by 17.5 GWh (49 percent) (see table 3). Similarly, for scenario 8, increasing the synchronized reserve requirement from 0 to 3.5 percent and then to 7 percent lowers the unserved energy by 9.5 GWh (11.5 percent) and 19.5 GWh (23.5 percent), respectively.
Furthermore, as synchronized reserves are increased, the incremental production costs are lower, as are the incremental consumer costs. Increasing the synchronized reserves to 7 percent lowers the consumer cost, as the consumers do not have to pay high energy prices for emergency sources.
These declines in consumer cost are magnified in scenario 8.
Comparing the two cases for 0 percent and 7 percent reserves of synchronized generation, we notice that for the latter case, sales increase by 19.45 GWh