Headquarters Daily Report NOVEMBER 19, 1997 *************************************************************************** REPORT NEGATIVE NO INPUT ATTACHED INPUT RECEIVED RECEIVED HEADQUARTERS û REGION I û REGION II û REGION III û REGION IV û PRIORITY ATTENTION REQUIRED MORNING REPORT - HEADQUARTERS NOV. 19, 1997 MR Number: H-97-0142 NRR DAILY REPORT ITEM GENERIC COMMUNICATIONS NRC Information Notice 97-79, "Potential Inconsistency in the Assessment of the Radiological Consequences of a Main Steam Line Break Associated with the Implementation of Steam Generator Tube Voltage-Based Repair Criteria," dated November 20, 1997. The NRC is issuing this information notice to notify addressees of a potential inconsistency in the assessment of the radiological consequences of a main steam line break associated with the implementation of a SG tube voltage-based repair criteria. Technical contacts: Stephanie M. Coffin, NRR 301-415-2778 Eric J. Benner, NRR 301-415-1171 _ HEADQUARTERS MORNING REPORT PAGE 2 NOVEMBER 19, 1997 MR Number: H-97-0143 NRR DAILY REPORT ITEM SIGNIFICANT EVENTS Subject: DC Cook, Units 1 and 2 - Degradation of ECCS and Containment Cooling Systems - Classified As A Significant Event The NRR/AEOD/RES Events Assessment Panel, on November 4, 1997, classified as a Significant Event for the Performance Indicator Program the multiple deficiencies found at the D.C. Cook Nuclear Power Plant, Units 1 and 2 affecting the emergency core cooling and containment heat removal systems. As a result, the safety margin of these systems to perform their intended recirculation and containment heat removal safety functions following a loss-of-coolant accident (LOCA) was significantly diminished. During the recirculation phase following a LOCA, the lower containment spray nozzles deliver water from the containment spray system to an annulus area beneath the ice condenser. The plant construction did not provide a flow path from this annulus area to the containment sump. Also, the plant design requires a manual switchover of the emergency core cooling system (ECCS) pump suctions from the refueling water storage tank (RWST) to the containment sump on low RWST level. As a result of flow bias errors and instrument uncertainties associated with the RWST level instrument, switchover could be performed before the assumed amount of water was available in the sump to support pump operation. Only by adding the volume of ice melt water to the sump inventory could vortexing be avoided. Finally, fibrous material installed on the electrical cable trays inside the containments of both units was postulated to dislodge during a LOCA and potentially block greater than 50 percent of the containment sump screens. In addition, clearances around the edge of the sump screens had exceeded the maximum particulate retention limit of 1/4", allowing particulates larger than 1/4" to enter the cooling system and potentially block the recirculation throttle valves. Either of these deficiencies could have created a common cause failure of the recirculation system to circulate water due to insufficient water in the sump or clogging of the recirculation throttle valves. Contact: William F. Burton, NRR/DRPM/PECB (301) 415-2853 _ REGION II MORNING REPORT PAGE 3 NOVEMBER 19, 1997 Licensee/Facility: Notification: Carolina Power & Light Co. MR Number: 2-97-0084 Robinson 2 Date: 11/19/97 Hartsville,South Carolina Dockets: 50-261 PWR/W-3-LP Subject: UPDATE TO REACTOR TRIP AT ROBINSON (33266) Reportable Event Number: 33266 Discussion: Following the reactor trip from 100 percent power on November 16, 1997, the licensee determined that the stub shaft which connects the motor to the pump on the B condensate pump had sheared. The shaft failed in the radial grove area of the keyway near the pump due to fatigue. During the transient, the motor continued to run. The operator noted lower current on the motor ammeter and zero condensate pump discharge pressure. A new stub shaft with a new design is currently being installed on the B condensate pump. The new design stub shaft had previously been installed on the A condensate pump. In addition, following the trip the source range channels NI 31 and 32 did not automatically energize at P-6. However, they were manually energized, but NI 32 did not indicate and intermediate range channel NI 35 indication was noted to be significantly under compensated. A loose signal cable was found in the amplifier cabinet on source range channel NI 32 and intermediate range channel detector NI 35 was replaced. The resident inspectors responded to the site and inspected the licensee corrective actions. Contact: M. Shymlock (404)562-4540 _ REGION IV MORNING REPORT PAGE 4 NOVEMBER 19, 1997 Licensee/Facility: Notification: Pacific Gas & Electric Co. MR Number: 4-97-0088 Diablo Canyon 2 Date: 11/19/97 Avila Beach,California Telephone Call from SRI Dockets: 50-323 PWR/W-4-LP Subject: UPDATE - UNIT 2 STARTUP TRANSFORMER REPLACEMENT Discussion: Pacific Gas and Electric Company has implemented numerous long-term actions to improve the short circuit withstand capability of the Diablo Canyon startup transformers and to provide a means to cope with normal control of the 230 kV grid system (one of two sources of off-site power). As part of these actions, the licensee replaced its startup transformers with improved, load tap changing transformers. The Unit 1 startup transformer was replaced during the last Unit 1 refueling outage earlier this year. Between November 8 and 17, 1997, the licensee replaced the Unit 2 startup transformer. This evolution was different from the Unit 1 replacement in that it was done while Unit 2 remained at power. Since 230 KV startup power feeds the site from a single line, the replacement activity required deenergizing startup power to both operating units for several hours. During this time, Units 1 and 2 were powered from their respective unit auxiliary transformers. The significance of these electrical alignments centers on the fact that the 500 KV feeder to the site is not available except by a manual transfer and backfeeding through the main transformer(s). Therefore, if a reactor trip had occurred, the plants would have immediately been in a natural circulation mode and, until 500 kV power could be established, electrical power would have been from the emergency diesel generators. Dismantling and removal of the existing Unit 2 startup transformer and installation of the new Unit 2 transformer were completed on November 14, 1997. After the new startup transformer was in place, it was energized with the supply breaker open for a 12-hour soak; subsequently, it was tested and at 9 p.m. on November 17 it was declared operational. Prior to the evolution, the licensee performed simulator training of the operators for loss of off-site power, unit trip, and related scenarios. They also implemented other contingencies, such as maintaining all diesel generators operable and preventing any other maintenance or testing activities to be performed, while startup power was unavailable. Licensee operations managers were present in the control room whenever startup power was unavailable for both units throughout the evolution. Regional Action: Several calls involving senior licensee, Region IV, and NRR management were conducted preceding the replacement activity. The calls allowed the NRC and the licensee to discuss and clarify the planning of, and contingency actions for, the evolution. Resident and region-based inspectors provided continuous coverage throughout those occasions when 230 kV startup power was unavailable. REGION IV MORNING REPORT PAGE 5 NOVEMBER 19, 1997 MR Number: 4-97-0088 (cont.) Contact: David Proulx (805)595-2354 Howard Wong (510)975-0296 _