05000282/FIN-2014005-04
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Finding | |
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| Title | Licensee-Identified Violation |
| Description | Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures and drawings of a type appropriate to the circumstance and be accomplished in accordance with these instructions, procedures and drawings. Contrary to the above, on December 30, 2013, the licensee identified that plant personnel performed Unit 2 SG hot gap checks, an activity affecting quality, without having documented instructions, procedures and drawings appropriate to the circumstance. Specifically, the design drawings failed to include information indicating that only one set of steam generator upper lateral support shims and bumpers was to be removed at a time during the hot gap clearance checks. Due to this deficiency, the workers removed all of the steam generator shims and bumpers which resulted in making the Unit 2 RCS inoperable and placing the unit in an unanalyzed condition. The inspectors determined that the licensees failure to have drawings appropriate to the circumstance for performing the hot gap clearance checks was a performance deficiency. The performance deficiency was evaluated in accordance with IMC 0612, Appendix B, Issue Screening. The inspectors determined that the performance deficiency did not involve a violation that impeded the regulatory process or contributed to actual safety consequences. The inspectors determined that the finding was more than minor because it impacted the design control and configuration control attributes of the initiating events cornerstone. In addition, the finding impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Table 3SDP APPENDIX ROUTER. The inspectors answered No to all the questions listed in Table 3; therefore, the risk evaluation continued with IMC 0609 Appendix A, The Significance Determination Process For Findings At-Power. Under the Initiating Events Cornerstone for Exhibit 1, the inspectors answered Yes to the question, After a reasonable assessment of degradation, could the finding result in exceeding the RCS leak rate for a small break LOCA? Therefore, the inspectors contacted the Region III Senior Reactor Analysts (SRAs) for a detailed risk evaluation. The SRAs performed a detailed risk evaluation for the effect of the missing SG shims on Unit 2 with regard to the change in core damage frequency (CDF). The evaluation assumed certain initiating events (such as seismic events) would impart a significant load upon the steam generators causing their displacement, which in turn could lead to breaks in the reactor coolant primary piping or secondary system piping. The SRAs reviewed the licensees risk evaluation for this issue as documented in: PRA Document No. V.SPA.14.010, Unit 2 SG Shim SDP Calculation, Rev. 1; PRA Document No. V.SPA.14.011, U2 SG Secondary Break Size Threshold, Rev. 1; and PRA Document No. V.SPA.14.009, Unit 2 SG Shim SDPMSLB and MFLB Initiating Event Frequency Development, Rev. 1. Based on review of the above licensee documents and input from the inspectors, the SRAs determined that the following initiating events would result in a change in CDF: Seismic Events; Large Loss of Coolant Accident Events; Main Steamline Breaks in Containment; and Main Feedwater Line Breaks in Containment. Other initiating events, such as steam generator tube ruptures and medium and small break LOCAs were determined not to result in a change in risk due to the missing shims. Following a steam generator tube rupture, imparted loads were small enough such that the connected primary and secondary piping were expected to remain intact and functional. Similarly, following medium and small break LOCAs the steam generators, secondary piping, and the unaffected primary loop were expected to remain intact and functional. According to the licensees Unit 2 SG Shim SDP Calculation referenced above, the duration when all shims on each SG were removed to the time when all of the shims were re-installed was about 20.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The calculation did not state the time when the first shim was removed; therefore, the SRAs doubled this exposure time and assumed 41 hour4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> duration for the exposure time for this finding, which was a conservative assumption. Also, the SRAs conservatively assumed that the initiating events subject to this analysis proceed directly to core damage without credit for mitigation or recovery (i.e., conditional core damage probability (CCDP) is 1.0). Seismic Events - The licensee screened out seismic events of magnitude greater than the design basis earthquake of level 0.12g for contributing to a change in CDF. Their analysis showed the primary and secondary side piping would remain intact and functional during seismic events less than 0.12g. The inspectors and SRAs accepted this assumption. The Risk Assessment of Operational Events Handbook listed the frequency of 0.08g and greater seismic events, and 0.15g and greater seismic events, as 1.907E04/yr and 7.272E05/yr respectively. Interpolating these values on a logarithmic scale resulted in a frequency occurrence for seismic events greater than 0.12g to be 1.024E04/yr. Assuming a conditional core damage probability of 1.0, the seismic contribution to the risk increase was taken to be frequency of the seismic event during the exposure time or 4.79E07/yr as calculated below: CDFseismic = [1.024E04/yr] * [41/8760] = 4.79E07/yr. Large Loss of Coolant Accidents - The SRAs used the Prairie Island Standardized Plant Analysis Risk (SPAR) Model Version 8.19 to obtain the frequency of a large loss of coolant accident (LLOCA). The SPAR model lists the frequency of LLOCAs as 2.50E06/yr. Assuming a conditional core damage probability of 1.0, the LLOCA contribution to the risk increase was taken to be frequency of the LLOCA during the exposure time or 1.17E08/yr as calculated below: CDFlloca = [2.50E06/yr] * [41/8760] = 1.17E08/yr. Main Steamline Breaks in Containment - For main steamline (MSL) breaks in containment, the licensee performed an evaluation that determined that only pipe breaks of certain sections of 5.5-inch diameter pipe and larger could result in loadings large enough to impact the change in CDF. The inspectors and SRAs accepted this assumption. The licensee calculated a MSL break initiating event frequency for 4inch equivalent diameter piping for this analysis using EPRI Report 3002000079, Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments (PRAs), Revision 3, and other plant documents and drawings. The licensee calculated a MSL break frequency of 4.45E05/yr. Assuming a conditional core damage probability of 1.0, the MSL break contribution to the risk increase was taken to be frequency of the MSL break during the exposure time, or 2.08E07/yr: CDFMSLB = [4.45E05/yr] * [41/8760] = 2.08E07/yr. Main Feedwater Line Breaks in Containment - For main feedwater line (MFL) breaks in containment, the licensee performed an evaluation that determined that only pipe breaks of certain sections of 5.5inch diameter pipe and larger could result in loadings large enough to impact the change in CDF. The inspectors and SRAs accepted this assumption. The licensee calculated a MFL break initiating event frequency for 4inch equivalent diameter piping for this analysis using EPRI Report 3002000079 and other plant documents and drawings. The licensee calculated a MFL break frequency of 3.53E06/yr. Assuming a conditional core damage probability of 1.0, the MFL break contribution to the risk increase was taken to be frequency of the MFL break during the exposure time, or 1.65E08/yr: CDFMFLB = [3.53E06/yr] * [41/8760] = 1.65E08/yr. Results - The total change in CDF (i.e., CDF) represents the sum of the individual CDF values above, or 7.16E07/yr. In regards to Large Early Release Frequency (LERF), IMC 0609 Appendix H, Containment Integrity Significance Determination Process, was used to determine the potential risk contribution due to LERF. Prairie Island is a two loop Westinghouse pressurized water reactor with a large dry containment. Sequences important to LERF include steam generator tube rupture events and inter-system LOCA events. These were not the dominant core damage sequences for this finding. Therefore, the risk significance due to the change in CDF and LERF was determined to be of very low safety significance (GREEN). The licensee documented this issue in the corrective action program as CAP 1412886. Corrective actions included re-installing the shims and bumpers, performing additional hot gap adjustments, and revising the upper lateral support drawings to specifically state that only one shim and bumper package can be removed at a time. |
| Site: | Prairie Island  |
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| Report | IR 05000282/2014005 Section 4OA7 |
| Date counted | Dec 31, 2014 (2014Q4) |
| Type: | NCV: Green |
| cornerstone | Mitigating Systems |
| Identified by: | Licensee-identified |
| Inspection Procedure: | |
| Inspectors (proximate) | B Boston B Jose D Mcneil D Passehl J Beavers J Bozga K Riemer K Stoedter M Holmberg M Phalen P Laflamme R Elliott V Meghani |
| Violation of: | 10 CFR 50 Appendix B Criterion V |
| INPO aspect | |
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Finding - Prairie Island - IR 05000282/2014005 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Finding List (Prairie Island) @ 2014Q4
Self-Identified List (Prairie Island)
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