Headquarters Daily Report MAY 06, 1996 *************************************************************************** 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 - REGION I MAY 6, 1996 Licensee/Facility: Notification: Pennsylvania Power & Light Co. MR Number: 1-96-0043 Susquehanna 1 2 Date: 05/06/96 Allentown,Pennsylvania SRI Phone Call Dockets: 50-387,50-388 BWR/GE-4,BWR/GE-4 Subject: Management Changes Discussion: Effective May 10, 1996, Mr. H. Gene Stanley, Vice President - Nuclear Operations, will retire from Pennsylvania Power & Light (PP&L) and accept the position of Site Vice President - Braidwood Station with Commonwealth Edison. Mr. George T. Jones, Vice President - Nuclear Engineering, will assume Mr. Stanley's responsibilities. Mr. Glenn D. Miller, Manager - Nuclear Plant Services, will be promoted to Manager - Nuclear Engineering, and will report directly to Mr. Jones. Mr. Anthony F. Iorfida will be promoted to replace Mr. Miller. Regional Action: Routine. Contact: Walter Pasciak (610)337-5258 Richard Urban (610)337-5271 _ REGION I MORNING REPORT PAGE 2 MAY 6, 1996 Licensee/Facility: Notification: Consolidated Edison Co. Of N.Y. MR Number: 1-96-0046 Indian Point 2 Date: 05/06/96 Buchanan,New York SRI PC Dockets: 50-247 PWR/W-4-LP Subject: TURBINE RUNBACK OF 4/30/96 Discussion: At 9:55 a.m. on April 30, 1996, the Indian Point Unit 2 turbine automatically ran back from 100 percent power to 97 percent power. The runback was caused by a blown control power fuse for power range nuclear instrument (NI) 41 and occurred during the performance of a surveillance test on the NI 41 circuitry. The blown fuse caused the dropped rod circuitry to actuate and this generated the turbine runback. The runback to 97 percent from 100 percent power was less than normally expected for a dropped rod runback and operators at first suspected that the runback circuitry was not operating properly; however, subsequent investigation revealed that the runback circuit had operated properly. At Indian Point 2, the turbine runback is accomplished by decreasing turbine control oil pressure through the turbine load limit device. A dropped rod runback causes the load limit oil pressure to decrease for 12 seconds or until turbine control oil pressure decreases to amount equivalent to about 85 percent power. The load limit oil pressure is usually set one pound above the turbine governor valve oil pressure. In this instance, governor oil pressure was set about one and one-half pounds above the control oil pressure for 100 percent power as a result of the method that the operators use to ensure that the turbine control valves are full open at full turbine load. Therefore, the load limit oil pressure was set about two and one-half pounds above the full load control oil pressure. When the runback circuit actuated, turbine load did not initially decrease as load limit oil pressure was higher than the control oil pressure for 100 percent. Once the load limit pressure decreased below the 100 percent control oil pressure, turbine load decreased. At the end of the 12 second timeout, turbine load had only been decreased to 97 percent power. There was no safety impact from the "shortened" runback as the runback signal was generated from a failed NI, not from an actual dropped rod. Also, the Unit 2 UFSAR dropped rod analyses were performed with no credit taken for a turbine runback and thermal limits are still maintained. Lastly, had the rod drop been real, the operators would have reduced turbine power to 85 percent as required by the alarm response and abnormal operating procedures. Regional Action: The resident staff observed the licensee's resolution of the problem. The blown fuse was caused by a problem in the power supply for NI 41 and was subsequently repaired. Contact: Richard Barkley (610)337-5065 _ REGION I MORNING REPORT PAGE 3 MAY 6, 1996 Licensee/Facility: Notification: Vermont Yankee Nuclear Power Corp. MR Number: 1-96-0045 Vermont Yankee 1 Date: 05/06/96 Vernon,Vermont RI/PC Dockets: 50-271 BWR/GE-4 Subject: NEW PRESIDENT AND CHIEF EXECUTIVE OFFICER OF VERMONT YANKEE Discussion: On May 3, 1996, the Vermont Yankee (VY) Nuclear Power Corporation named Ross P. Barkhurst as President and Chief Executive Officer. Mr. Barkhurst replaces Gary Weigand who will retire this month. Mr. Barkhurst comes to VY from Entergy Operations, Inc., where he was the Vice President - Operations, responsible for daily operations at Entergy's Waterford 3 nuclear plant near New Orleans, LA. Prior to becoming a Vice President at Entergy Operations, Mr. Barkhurst was the plant manager at Waterford 3 and had also held positions as operations and maintenance manager at the Trojan nuclear plant in Oregon. Regional Action: None Contact: William Cook (315)342-4907 _ REGION II MORNING REPORT PAGE 4 MAY 6, 1996 Licensee/Facility: Notification: Tennessee Valley Authority MR Number: 2-96-0041 Sequoyah 2 Date: 05/06/96 Soddy-Daisy,Tennessee Dockets: 50-328 PWR/W-4-LP Subject: SAFETY INJECTION SYSTEM PIPE CRACK AT SEQUOYAH UNIT 2 Discussion: Region 2 was informed on May 2, 1996 of TVA's discovery of a safety injection system pipe crack during a UT inspection on Sequoyah Unit 2. The reactor is shutdown and defueled. Routine ISI, pursuant to ASME Section XI, was in progress. The pipe crack is reported to be a 75 percent through wall circumferential crack, about 7 inches long on the upstream side of the final check valve (CV 63-560) between the injection line and the RCS cold leg. The piping is 10-inch, schedule 140, stainless steel pipe. The crack is described as initiating on the inside diameter of the pipe, is in the base metal adjacent to the weld area between the check valve and the pipe and is centered on the top dead center of the pipe. No through-wall leakage was reported. The licensee's preliminary assessment is that the crack was caused by thermal cycling of the piping due to thermal striping from back-leakage through the check valve, onto a weld with high residual stresses caused by four cycles of weld repair during original construction. The licensee will remove a 10-inch long section of pipe, including the defective area and send it to Westinghouse for metallurgical analysis. The licensee reviewed the leakage history for all of the Unit 1 and Unit 2 injection isolation check valves. Check valve CV 63-560, on the line with the pipe crack, appeared to have the best history for leakage, with the fewest noted incidences of leakage and the lowest leakage amounts. Measured leak rates ranged from 0.1 to 0.4 gpm. The licensee has also conducted a review of construction records and past inspection records for this weld and the welds adjacent to the other cold-leg and hot-leg injection isolation check valves, for both units. The construction records showed that weld No. SIF-146 (where the cracked line is located) was rejected by QC and repair welded four times during original construction, with the grind-out and repairs occurring on the top of the pipe in the area where the crack is located. The licensee also found other welds which had been repair welded during construction, but this weld is the only one with more than one repair cycle. The licensee has conducted augmented Ultrasonic examinations of the welds on both sides of all of the injection isolation check valves on Unit 2, and have reviewed ISI inspection history for Unit 1. Due to the additional inspections conducted on Unit 2 welds, and the unique weld repair history of the cracked weld, the licensee has no immediate operational concerns about the welds in Unit 1, which is operating. This discovery is similar to the Farley thermal fatigue induced leak that resulted in the issuance of Bulletin 88-02 (Thermal Stresses in Piping connected to Reactor Coolant Systems). REGION II MORNING REPORT PAGE 5 MAY 6, 1996 MR Number: 2-96-0041 (cont.) Regional Action: The residents continue to followup on licensee activities. Contact: Scott Sparks (404)331-5619 _ REGION IV MORNING REPORT PAGE 5 MAY 6, 1996 Licensee/Facility: Notification: Arizona Public Service Co. MR Number: 4-96-0043 Palo Verde 2 Date: 05/04/96 Wintersburg,Arizona TELEPHONE CALL FROM RESIDENTS Dockets: 50-529 PWR/CE80 Subject: COMPLETION OF REFUELING OUTAGE Discussion: At 6:57 a.m. (MST) on May 4, 1996, the main generator for Palo Verde Unit 2 was synchronized to the grid, ending the unit's sixth refueling outage. The outage began on March 16, 1996, and was scheduled for completion on May 4. The licensee performed extensive steam generator tube eddy current inspections during the outage, which resulted in a total of 319 tubes being plugged. The licensee also performed steam generator secondary side modifications to increase the recirculation ratio and wetting of the tubes. The licensee replaced all four reactor coolant pump seal packages with a new design that reduces seal leakage. Finally, the licensee replaced 120 of 240 Class 1E battery cells due to degradation of the AT&T round cells. During the outage, the licensee found a stuck fuel assembly which had been compressed and damaged from installation of the upper guide structure during the previous refueling outage. The licensee developed special equipment for removal of the fuel assembly, which included cables to support the fuel rods and tools to cut the lower supports of the fuel assembly. In addition, Palo Verde received a license amendment from NRR to use alternate rigging equipment for removal the assembly. NRC personnel from Region IV reviewed the licensee's plans to remove the assembly and observed the successful removal of the assembly. News of the stuck fuel assembly generated considerable media interest. During the outage, the licensee also experienced two simultaneous fires in the control building which resulted in the declaration of an Alert. The fires resulted in degradation of control room emergency and essential lighting but did not affect control room activities. The licensee determined that a design problem with the location of circuit ground wiring contributed to the fires. NRC resident inspectors were onsite during the fires and responded to the unit. The licensee implemented design changes to resolve wiring issue prior to restart of the unit. Unit 2 is currently at 66 percent power and is performing power ascension testing. Regional Action: NRC resident inspectors are following the licensee's actions to return Unit 2 to full power. Contact: D. Kirsch (510)975-0290 J. Kramer (602)386-3638 _