05000354/LER-2009-002
| Docket Number | |
| Event date: | 04-18-2009 |
|---|---|
| Report date: | 08-18-2009 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications |
| 3542009002R01 - NRC Website | |
PLANT AND SYSTEM IDENTIFICATION
General Electric — Boiling Water Reactor (BWR/4) Main Steam — EIIS Identifier {SB}* Safety Relief Valves — EIIS Identifier (--/RV)* *Energy Industry Identification System {EIIS} codes and component function identifier codes appear as {SS/CCC}
IDENTIFICATION OF OCCURRENCE
Event Date: April 18, 2009 Discovery Date: April 18, 2009
CONDITIONS PRIOR TO OCCURRENCE
Hope Creek was in Operational Condition 5 for the fifteenth refueling outage. No structures, systems or components were inoperable at the time of discovery that contributed to the event.
DESCRIPTION OF OCCURRENCE
On April 18, 2009, Engineering personnel began to receive the results of the Main Steam Safety Relief Valve (SRV){SB/RV} (Target Rock Model 7567F) setpoint testing required by Technical Specification 4.4.2.2. The initial report documented the failure of SRVs C, and F to meet the TS 3.4.2.1 limit of +/- 3%. Action a of TS 3.4.2.1 specifies "With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />". At the time, Hope Creek was in OPCON 5 (refueling) with the reactor head removed and the reactor cavity flooded and connected to the spent fuel pool for refueling operations. An expanded scope of review was instituted and all fourteen SRV pilot valves were ultimately removed, tested and replaced.
SAFETY CONSEQUENCES AND IMPLICATIONS
A bounding analysis was performed and documented in NEDC-32511P, "SAFETY REVIEW FOR HOPE CREEK GENERATING STATION SAFETY/RELIEF VALVE TOLERANCE ANALYSIS." This analysis supported the increase in allowable Technical Specification (TS) setpoint drift from + 1 percent to + 3 percent. An individual SRV upper limit lift setpoint of 1250 psig with 13 SRVs available out of a total of 14 was assumed in the calculation. The calculated peak vessel pressure at the bottom of the reactor vessel was 1331 psig. This provides a margin of 44 psig to the ASME upset limit of 1375 psig.
In addition, the GE analysis also evaluated the mechanical loads that occur on the SRV discharge piping when a SRV actuates. The analysis established a maximum allowable percentage increase (MAPI) for each SRV line such that the allowable mechanical stresses on the SRV discharge piping would not be exceeded.
Five of the six valves met their individual acceptance limits. The "A" SRV exceeded its limit of +3% with an as-found setpoint of 5.8%. The GE analysis of the mechanical stresses was performed for the Pacific Scientific (PSA) snubbers installed at the time the analysis was conducted. Hope Creek has since installed Lisega hydraulic snubbers in place of the PSA snubbers.
The discharge piping analysis contained in NEDC-32511P was re-assessed to ensure that the previous analysis (based on PSA snubbers) was still valid. A review and analysis of the differences between the snubbers determined that the PSA analysis was still bounding the present plant configuration. NEDC 32511P identifies a maximum increase in the nominal setpoint of "A" SRV to be 3%, without exceeding allowable stresses. The "A" SRV lifted at 5.8% above nominal setpoint. RIS 2005-20 and NRC Inspection Manual Part 9900 Technical Guidance on "Operability Determinations and functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety" allow the use of the criteria in Appendix F of Section III of the ASME Boiler and Pressure Vessel code for operability determinations. The re-evaluation has determined that the ASME III allowable stresses on the piping system are higher than the stresses that would have been seen had the "A" SRV lifted. There is no present operability concern due to the replacement of this pilot assembly with a fully tested spare.
Based on the above, and because none of the SRVs exceeded the 1250 psig analyzed limit, there was no impact to the health and safety of the public.
L The final test results for the SRVs that had setpoint drift outside the tolerance were as follows:
Valve ID As Found TS Setpoint Acceptable Band % Difference (psig) (psig) (psig) Actual Limit F013A 1195 1130 1096 —1163 5.80% 3.00% F013C 1203 1130 1096 —1163 6.50% 21.80% F013F 1163 1108 1075 —1141 5.00% 5.50% F013G 1156 1120 1087 —1153 3.20% 8.70% F013K 1212 1108 1075 —1141 9.40% 22.40% F013L 1170 ' 1120 1087 —1153 4.50% 16.30% The limit is based on the SRV discharge piping mechanical stress limit identified in Table 7-1 of GE analysis (NEDC-32511P) and is known as the "Maximum Allowable Pressure Increase" (MAPI).
A review of this event determined that a Safety System Functional Failure (SSFF) has not occurred as defined in Nuclear Energy Institute (NEI) 99-02.
CAUSE OF OCCURRENCE
The BWR industry has noted problems with the SRVs in that there are three (3) conditions that typically cause setpoint drift. These are (1) corrosion bonding of the pilot disk and seat; (2) excessive wear of internal parts; and (3) misalignment of internal parts. Disassembly of the SRVs was performed by the manufacturer at the offsite test facility (NWS Technologies) and witnessed by Hope Creek (HC) Programs Engineering personnel.
Five of the six SRVs tested displayed classical symptoms of corrosion bonding between the pilot disk and seat. A scanning electron microscope (SEM) was used to view the seating surfaces of a representative pilot disk and seat assembly at the Southwest Research Institute. The SEM examinations showed clear evidence of brittle oxide fracture along the seating line. These sharp fracture lines are typically produced as a brittle oxide growth between the two surfaces fractures upon the first cycle of the valve, increasing the lift setpoint.
The SRV pilots were cycled two times on a test stand that duplicated system (temperature, pressure) conditions, during as-found testing. In five of the six valves, the second lift setpoint was within the original tolerance band. This indicates that the problem was corrosion bonding between the disk and seat surfaces.
Once the oxide layer was broken, the lift setpoint returned to its original value.
For the sixth SRV, the bellows assembly was noticeably distorted. For this pilot, both lift setpoints were high (+6.5% and +6.8%). No other damage was found on any of the other pilot valves.
PREVIOUS OCCURRENCES
A review of LERs for the three prior years at Hope Creek was performed to determine if a similar event had occurred. There was a similar event during the 2006 Hope Creek refueling outage when three SRVs were found out of the TS required limits of +/- 3%. This event was reported as LER 354/06-003-00. Actions taken at that time were effective in that the following refueling outage did not have any SRV setpoint drift outside the allowable band on the SRVs tested.
CORRECTIVE ACTIONS
1. The pilot assembly of each failed SRV was replaced with a pre-tested, certified spare.
2. All 6 SRV pilot valve assemblies that failed were disassembled and inspected to determine the cause of the setpoint drift. (Corrective Action Program (CAP) number: 70096933 / 0170 - Complete) 3. All 14 SRV pilot valves will be removed, tested and replaced with pre-tested, certified spare pilot valves during the next refueling outage (RF16). (CAP number: 70096933 / 0180) 4. An equipment apparent cause evaluation was performed to document the cause(s) of the failures and determine any additional corrective actions. (CAP number: 70096933 / 0070 - Complete)
COMMITMENTS
This LER contains no commitments.