05000440/LER-2013-003
| Perry Nuclear Power Plant, Unit 1 | |
| Event date: | 06-15-2013 |
|---|---|
| Report date: | 10-04-2013 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| Initial Reporting | |
| ENS 49121 | 10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown, 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded |
| 4402013003R01 - NRC Website | |
Energy Industry Identification System (EllS) codes are identified in the text as [XX].
INTRODUCTION
On June 16, 2013, at 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, a controlled plant shutdown was conducted in accordance with Technical Specification (TS) 3.4.5, RCS Operational LEAKAGE, to repair reactor coolant pressure boundary leakage inside the Drywell. Both initiation of the shutdown required by TS and the principal safety barrier degradation were reported to the NRC at 0242 hours0.0028 days <br />0.0672 hours <br />4.001323e-4 weeks <br />9.2081e-5 months <br />, June 16, 2013, in accordance with 10 CFR 50.72(b)(2)(i) and 10 CFR 50.72(b)(3)(ii)(A); reference ENF Notification No. 49121. The reactor shutdown was completed at 0340 hours0.00394 days <br />0.0944 hours <br />5.621693e-4 weeks <br />1.2937e-4 months <br /> on June 16, 2013, when the reactor went subcritical during control rod insertion. A manual reactor protection system (RPS) [JC] actuation was used to insert the remaining withdrawn control rods. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(A), 10 CFR 50.73(a)(2)(ii)(A), and 10 CFR 50.73(a)(2)(iv)(A).
EVENT DESCRIPTION
Since Cycle 15 operations commenced on May 16, 2013, above normal levels of unidentified Drywell sump in-leakage were experienced. The unidentified Drywell sump in-leakage increased from 0.31 gallons per minute (gpm) to 0.58 gpm, which are above the typical Cycle 14 levels of approximately 0.2 gpm. This condition was entered in the corrective action program (CAP) and was being monitored in accordance with plant procedures and an approved Operational Decision Making Issue document. The Limiting Condition for Operation (LCO) TS 3.4.5.b limit for RCS unidentified operational leakage is less than or equal to 5 gpm.
On June 14, 2013, at 1900 hours0.022 days <br />0.528 hours <br />0.00314 weeks <br />7.2295e-4 months <br /> with the plant operating in Mode 1, a power reduction from 100 percent rated thermal power (RTP) was commenced to establish plant conditions to perform a Drywell inspection in order to determine the source of the unidentified leakage. On June 15, 2013, at approximately eight percent RTP, an inspection of the Drywell was conducted.
The inspection identified two leak sites. One leak was at the reactor pressure vessel flange connection for control rod drive mechanism (CRDM) 30-15 [AA] in the undervessel region. The other leak was at the top of Reactor Recirculation system [AD] flow control valve (FCV) B [FCV] 1633F0060B. Both leak sources were entered in CAP.
A Drywell entry determined that the leakage was at a three-quarter inch diameter vertical vent appendage, located off the top of the FCV. This vent appendage has double root isolation valves in series with a pipe cap at its end. Valves 1633F0647B and 1633F0648B [VTV] provide double isolation for venting and are welded in a socket weld joint configuration. The socket weld leg on the inlet to the first vent valve, 1633F0647B, was cracked circumferentially.
The leakage, estimated at 0.2 gpm, represented RCS pressure boundary leakage. TS LCO 3.4.5.a states that RCS operational LEAKAGE shall be limited to no pressure boundary LEAKAGE. On June 16, 2013, at 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, the operators commenced a controlled plant shutdown from approximately eight percent RTP in compliance with TS to repair the leak. Both the shutdown required by TS and the degraded principal safety barrier were reported in ENF No. 49121. The operators had entered TS 3.4.5 Condition C, "Pressure boundary LEAKAGE exists." and performed Required Action C.1, "Be in MODE 3." (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) and C.2, "Be in MODE 4." (36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />).
At 0313 hours0.00362 days <br />0.0869 hours <br />5.175265e-4 weeks <br />1.190965e-4 months <br />, the plant entered Mode 2 when the operators placed the mode switch in the Startup/Hot Standby position.
The type of plant shutdown conducted was a rapid soft shutdown where the operators insert control rods manually. At 0340 hours0.00394 days <br />0.0944 hours <br />5.621693e-4 weeks <br />1.2937e-4 months <br />, the Unit Supervisor declared the reactor subcritical based on in-core nuclear instrumentation readings. The operators continued to insert control rods in accordance with the established shutdown sequence. At 0353 hours0.00409 days <br />0.0981 hours <br />5.83664e-4 weeks <br />1.343165e-4 months <br />, the rod control and information system (RC&IS) [AA] malfunctioned preventing normal control rod movement. The operators entered the off-normal instruction for inability to move control rods. At 0403 hours0.00466 days <br />0.112 hours <br />6.66336e-4 weeks <br />1.533415e-4 months <br />, a manual reactor scram was inserted to complete the shutdown in accordance with normal operating procedures and the evolution specific reactivity plan termination criteria. All withdrawn control rods at the time fully inserted and there were no complications experienced in the scram. Mode 3 was entered at 0403 hours0.00466 days <br />0.112 hours <br />6.66336e-4 weeks <br />1.533415e-4 months <br />. The scram was reset at 0410 hours0.00475 days <br />0.114 hours <br />6.779101e-4 weeks <br />1.56005e-4 months <br />.
Mode 4 was entered at 1358 hours0.0157 days <br />0.377 hours <br />0.00225 weeks <br />5.16719e-4 months <br />.
CAUSE OF EVENT
The cause of the through wall leak at the inlet socket weld to 1B33F0647B is a combination of stress corrosion cracking and fatigue, which is referred to as corrosion fatigue. Age-related coincident factors worked together to result in a breakdown of the material and to create a susceptibility to corrosion fatigue.
Stress corrosion cracking requires a susceptible material, a corrosive environment, and a tensile stress. Stainless steel is a material that is susceptible to stress corrosion cracking and to corrosion fatigue. The crevice formed from the socket weld provides for a natural accumulation of contaminants that are not readily flushed as they are isolated from the flow stream. Fatigue stresses can be either thermal fatigue or vibration fatigue. In this case, the fatigue stress was caused by vibration. Therefore, the cause of this event has been attributed to corrosion fatigue.
The vent valve appendage had been in-service approximately 27 years prior to failure of the weld.
EVENT ANALYSIS
The initial reactor downpower to eight percent RTP and the rapid soft shutdown were performed in accordance with plant operating procedures and the reactivity plan. The RC&IS malfunction and the manual RPS actuation occurred after the reactor was subcritical. No plant parameters experienced in the shutdown process challenged the transients described in the Updated Safety Analysis Report Chapter 15, Accident Analysis.
The reactor recirculation system (RRS) provides a forced coolant flow through the core to remove heat from the fuel to allow operation at significantly higher power levels than would otherwise be possible. The system consists of two recirculation flow loops each consisting of a motor driven pump and a flow control valve. The RCS pressure boundary leak, as described, would not have prevented RRS flow control valve B from performing its design function.
A qualitative probabilistic risk assessment (PRA) was performed for this event. While RCS pressure boundary leakage was present, this leakage did not require an immediate scram. The PRA model does not consider a controlled plant shutdown as an initiating event. Furthermore, the given condition did not make any PRA modeled equipment/functions unavailable. Therefore, the PRA assessment concludes there are no changes in core damage frequency (CDF) or large early release frequency (LERF). The delta CDF and delta LERF values remain well below the acceptable thresholds of 1.0E-06/yr and 1.0E-07/yr respectively as discussed in Regulatory Guide 1.174.
Plant configurations with changes in CDF of less than 1.0E-06 and LERF of less than 1.0E-07 are not considered to be significant risk events. Based on the PRA results, the safety significance of this event is considered to be small.
CORRECTIVE ACTIONS
Visual (VT-2) and liquid penetrant (PT) inspections were performed on the other vent and drain appendages for the RRS flow control valves. Examinations of all welds on these valves were satisfactory with no indications of surface cracks.
A new vent valve assembly was fabricated and installed on 1633F0060B. The schedule 80 pipe originally installed between 1633F0060B and 1633F0647B was replaced with schedule 160 pipe.
The socket weld was built up to the design dimensions. This new configuration is stiffer, resulting in a higher natural frequency of the appendage. This new configuration is less likely to be impacted by resonant vibrations that adversely affected the previous designed appendage.
The removed vent valve assembly containing the cracked weld was sent off-site to a qualified testing facility for metallurgical failure analysis. The results are discussed earlier in this LER.
Design configuration options will be evaluated to minimize the sensitivity of unsupported appendages on the RRS piping to corrosion fatigue. The options include use of additional supports, modifying the line stiffness, elimination of appendages, and use of corrosion resistant material.
The flange connection for CRDM 30-15 is a mechanical joint and was reworked to eliminate any reactor water leakage. Corrective actions to repair the RCS pressure boundary leakage and the CRDM flange connection restored Drywell unidentified leakage back to less than the previous operating cycle leakage.
PREVIOUS SIMILAR EVENTS
A review of LERs and the corrective action database for the past three years did not identify any previous similar events or condition reports associated with RCS pressure boundary leakage. Two LERs were written for completion of shutdown required by TS. These include LER 2011-002-01, Condition Prohibited by Technical Specifications and Plant Shutdown due to Unit 1 Startup Transformer Issues, and LER 2010-003, Loss of Control Rod Drive Header Pressure Results in Manual RPS Actuation. None of the corrective actions for these LERs would have been reasonably expected to prevent the event documented in LER 2013-003.
COMMITMENTS
There are no regulatory commitments for these LERs contained in this report. Actions described in this document represent intended or planned actions, are described for the NRC's information, and are not regulatory commitments.