05000249/LER-2001-003
| Event date: | 07-05-2001 |
|---|---|
| Report date: | 09-04-2001 |
| 2492001003R00 - NRC Website | |
PLANT AND SYSTEM IDENTIFICATION:
General Electric — Boiling Water Reactor — 2527 MWt rated core thermal power Energy Industry Identification System (EIIS) Codes are identified in the text as [XX] and are obtained from IEEE Standard 805-1984, IEEE Recommended Practice for System Identification in Nuclear Power Plants and Related Facilities.
EVENT IDENTIFICATION:
Reactor SCRAM due to Increasing Drywell Pressure
A. PLANT CONDITIONS PRIOR TO EVENT:
Unit: 3 � Event Date: 07-05-2001 Reactor Mode: 1 � Mode Name: Power Operation Reactor Coolant System Pressure: 1000 psig
B. DESCRIPTION OF EVENT:
Event Time: 1006 Power Level: 100% This condition is being reported pursuant to 10 CFR 50.73 (a)(2)(iv)(B), which requires the reporting of any event or condition that resulted in a manual or automatic actuation of the Reactor Protection System (RPS) [JC] including reactor scram or reactor trip.
On July 5, 2001 at 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br />, the Unit 3 Nuclear Station Operator (NSO) observed drywell to torus differential pressure was slightly elevated during routine panel monitoring. Both indications, drywell pressure and drywell to torus differential pressure, were indicating approximately 1.3 psig on Unit 3. Because atmospheric conditions could cause this response, the Unit 3 NSO communicated with the Unit 2 NSO for comparison of drywell differential pressure.
The Unit 2 drywell pressure was approximately 1.14 psig and stable. At this time, an additional NSO was requested to assist in the determination of the indicated elevated drywell pressure.
As pressure continued to increase, the NSOs consulted the Unit Supervisor. The Unit Supervisor advised the NSO to manually Scram the reactor when drywell pressure reached 1.5 psig. At this time, there were no other abnormal alarm indications.
Drywell temperature, and therefore drywell pressure continued to increase, and at 1006 hours0.0116 days <br />0.279 hours <br />0.00166 weeks <br />3.82783e-4 months <br /> a manual Scram was inserted at 1.49 psig. Drywell pressure continued to slowly increase. At 1009 hours0.0117 days <br />0.28 hours <br />0.00167 weeks <br />3.839245e-4 months <br /> the pressure reached 1.71 psig, at which time Emergency Core Cooling System (ECCS) equipment initiated on drywell high pressure (Unit 2/3 and Unit 3 diesel generators [EK] ran unloaded, Core Spray [BM] and LPCI [BO] initiated and operated in recirculation mode). High Pressure Coolant Injection (HPCI) [BJ] was placed in pull-to-lock to prevent a cold water injection. All ECCS initiated and operated as required.
At 1019 hours0.0118 days <br />0.283 hours <br />0.00168 weeks <br />3.877295e-4 months <br />, a GSEP Alert level was conservatively declared based on the assumption that the drywell pressure increased due to RCS leakage. At 1036 hours0.012 days <br />0.288 hours <br />0.00171 weeks <br />3.94198e-4 months <br /> a pressure of 2.0 psig was reached and peaked at 2.3 psig. Based on observations by Operations during the event, the potential for failure of the 3B RBCCW [CC] TCV existed. At 1113 hours0.0129 days <br />0.309 hours <br />0.00184 weeks <br />4.234965e-4 months <br />, the 3A RBCCW pump was started and aligned to the 3A RBCCW heat exchanger. At 1128 hours0.0131 days <br />0.313 hours <br />0.00187 weeks <br />4.29204e-4 months <br /> drywell pressure had decreased to less than 2.0 psig (one and a half-hours after the initiation of the event).
At 1435 hours0.0166 days <br />0.399 hours <br />0.00237 weeks <br />5.460175e-4 months <br />, drywell gaseous atmospheric sample indicated normal airborne activity levels, which was indicative of no abnormal RCS leakage. At 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br />, Operations reported drywell sumps indicate normal leakage (indicative of no RCS leakage). At 1530 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.82165e-4 months <br /> a maintenance crew performed testing that indicated that the 3B RBCCW Heat Exchanger Service Water Outlet TCV (throttles service water) appeared to have some kind of disc separation/damage, interrupting flow. The Alert was terminated at 1602 hours0.0185 days <br />0.445 hours <br />0.00265 weeks <br />6.09561e-4 months <br />, on July 5, 2001.
C. CAUSE OF EVENT:
Subsequent investigation revealed that the Unit 3B TCV had failed due to inappropriate torqueing of the valve stem into the valve disc. This inappropriate action led to the disc dropping into the seat of the valve and thus obstructing the flow path of cooling water to the RBCCW heat exchanger.
Upon disassembly of the valve, it was noted that the holes for the roll pin lined up when the stem was threaded hand- tight into the disc. When the stem was properly torqued into the disc, the holes did not align. This indicates that the stem was not torqued into the disc, producing additional stresses on the pin due to flow through the system (i.e.
vibration). Because stress is one component of stress corrosion cracking, this additional stress is a key component of the failure. If the disc had been properly torqued, there would be no additional stresses on the pin and this event would not have occurred. The manufacturer's valve assembly procedure requires that the stem be torqued into the plug and a solid 300 series Stainless Steel pin to be used. This has been determined to be the root cause of this event. (NRC Cause Code B) A contributing cause to the event was that prior to 1999, the RBCCW system was operated in a parallel configuration, with a two-pump/heat exchanger combination. In 1999, after RBCCW system was balanced, it was determined that only a one-pump/heat exchanger was required to be in operation.
D. SAFETY ANALYSIS
Although the Unit was manually scrammed as a result of increasing pressure in the Drywell, this event was of minimal safety significance. All rods fully inserted during the manual scram, all Group 2 and Group 3 isolation valves successfully closed or isolated, and all ECCS responded satisfactorily. Reactor level was maintained using normal Feedwater control and Main Turbine bypass valves and the Main Condenser was used to remove decay heat.
A shutdown risk assessment was performed that showed that the overall window and all individual windows remained GREEN for the duration of the outage. There was no impact on the non-outage unit and the Technical Specifications were met. Therefore, the safety significance of this event is minimal.
E. CORRECTIVE ACTIONS:
Disassembled and repaired the 3B RBCCW TCV. (Complete) Evaluated and implemented the operation of two RBCCW pumps and two heat exchangers per unit. (Complete) Develop a plan for long term operation of the two RBCCW pumps and heat exchangers. (ATI 56390-10) Disassemble and install the correct retaining pin properly in the remaining RBCCW TCVs. Verify that the TCV stem is properly torqued to its disc. (ATI 56390-11)
F. PREVIOUS OCCURRENCES:
There was a previous similar occurrence at Quad Cities. The failure of their RBCCW TCV did not result in a unit scram since two RBCCW heat exchangers per unit were operating at the time. A Nuclear Operations Notification (NON) was not generated as a result of the Quad Cities event. An OPEX search was performed and no previous similar events have been reported. A similar search was performed on Dresden's Condition Reporting database, and no previous events have been reported.
G. COMPONENT FAILURE DATA:
Copes-Vulcan Temperature Control Valve Class 125, D style control valve with 600-160L direct acting actuator, with anti-cavitation trim.