05000333/LER-2012-009

LER-2012-009, Containment Atmosphere Dilution (CAD) System Valves Misaligned for Ascension into Mode 2

James A. Fitzpatrick Nuclear Power Plant
Event date:
Report date:
3332012009R00 - NRC Website

BACKGROUND  At 0006 on November 15, 2012, T/S SR 3.6.1.3.1 was performed satisfactorily (SAT) (verify each 20 and 24 inch PCIV is closed), this complied with its frequency requirement of once every 31 days per Appendix I of the JAFNPP Technical Requirements Manual (TRM). (There are no other frequency or mode change requirements associated with this T/S SR).

At 1121 on November 21, 2012, the Shift Manager signed off that the SGT ISOL valve was closed on the startup and shutdown procedure checklist.

At 0117 on November 23, 2012 procedure “Vent and Purge Operation of Drywell and Torus with Drywell and Torus Depressurized and Primary Containment Not Required” commences. The procedure opens the 12 inch diameter SGT ISOL, the 20 inch diameter PCIV valves and the 24 inch diameter PCIV valves.

At 0637 on November 24, 2012, the shift turnover notes correctly list the vent and purge procedure as still being in progress; however the containment is noted as “de-inerted – vent and purge secured" in the Ops Log. The oncoming shift did not recognize that the current valve lineup for the CAD system is incorrect for the scheduled Mode Ascension planned for that shift. It is incorrectly assumed by the operator on the oncoming shift that the vent and purge operation had been completed and that the valve line up previously verified by T/S SR 3.6.1.3.1 had been restored to SAT in accordance with the steps in the Vent and Purge procedure to secure from the evolution.

At 1130 hours0.0131 days <br />0.314 hours <br />0.00187 weeks <br />4.29965e-4 months <br /> on November 24, 2012, the Final Prestart Check off in the shift narrative log is completed SAT.

At 1135 hours0.0131 days <br />0.315 hours <br />0.00188 weeks <br />4.318675e-4 months <br /> on November 24, 2012, the James A. FitzPatrick Nuclear Power Plant (JAFNPP) entered Mode 2 from Mode 4. At that time, the containment penetration flow paths for the 20 inch diameter PCIVs and 24 inch diameter PCIVs became “inoperable” in accordance with T/S 3.6.1.3 Action B.1 due to the vent and purge of the Torus and Drywell evolution not being completed properly prior to the mode change which left the valves in their open position. Concurrently one train of the Stand By Gas Treatment System and the pressure suppression function of Primary Containment also because inoperable because of the CAD System valve lineup.

At 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> on November 24, 2012, oncoming shift notices that the containment vent and purge valves are open during panel walk down.

At 1838 hours0.0213 days <br />0.511 hours <br />0.00304 weeks <br />6.99359e-4 months <br /> on November 24, 2012, the affected flow path penetrations were isolated by closure of 12 inch SGT ISOL valve (the full flow line to the standby gas treatment system).The penetration isolation PCIV valves are also closed. This action restores the penetration flow paths, primary containment and the one train of standby gas treatment system to operable.

With regards to the UFSAR and current operating procedures the following is noted:

 JAFNPP UFSAR Section 5.2.3.6 cautions against the 20 inch diameter Primary Containment Isolation Valves (PCIVs) and 24 inch diameter PCIVs being open simultaneously for ensuring that a suppression bypass condition is not created.

 Current operating procedures prohibit purging and/or venting of the drywell and torus simultaneously when primary containment integrity is required On April 2, 2013, after consulting with the NRC resident inspector, JAFNPP management concluded the event that occurred at 1135 hours0.0131 days <br />0.315 hours <br />0.00188 weeks <br />4.318675e-4 months <br /> on November 24, 2012, was a reportable condition, and that the relaxation to mode change restrictions provided in SR 3.0.4 by utilizing the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> grace period provided in SR 3.0.3 to delay declaring an SSC inoperable during mode change ascensions was inappropriately applied in this event. It was determined that the condition did not meet the intended purpose of the flexibility provided by Technical Specification Task Force (TSTF) Travelers TSTF-358 and TSTF-359 respectively for continuing mode ascensions with an inoperable SSC. Therefore the condition should have been reported under 10 CFR 50.73 (a)(2)(i)(B) as a condition prohibited by Technical Specifications for a violation of LCO 3.0.4.

EVENT DESCRIPTION

At 1135 hours0.0131 days <br />0.315 hours <br />0.00188 weeks <br />4.318675e-4 months <br /> on November 24, 2012, JAFNPP transitioned into Mode 2 from Mode 4. At that time, the associated penetration flow paths for the venting and purging operation which includes 20 inch diameter PCIVs and 24 inch diameter PCIVs became “inoperable” (this is the conservative time that the licensee will begin the required action time clock of the underlying T/S required actions and completion times). Concurrently, one train of the Stand-By Gas Treatment system as well as Primary Containment also became inoperable due to the potential flow path of the dynamic effects of a LOCA on the Stand- By gas treatment filters and the pressure suppression function of the torus.

At 1838 hours0.0213 days <br />0.511 hours <br />0.00304 weeks <br />6.99359e-4 months <br /> on November 24, 2012 the affected flow path penetrations were isolated by closure of 12 inch SGT ISOL valve (the full flow line to the standby gas treatment system). Additionally, the 20 inch diameter PCIVs and 24 inch diameter PCIVs are also secured close. By completing this action, the penetration flow paths were restored to operable status. This was verified by the data points of the respective valves from the EPIC computer.

Securing the penetration flow paths also restored the train of the stand-by gas treatment system and primary containment to operable.

The required actions were performed within the required completion times of the T/S LCO 3.6.1.3 Action F.1, T/S LCO 3.6.1.1 Action B.1, and T/S LCO 3.6.4.3 Action A.1, albeit inadvertently by the operators. It was determined during the review of the event, that the actions taken by the operators resulted in the condition continuing to remain bounded by the T/S action time limits of LCO 3.6.1.3 Action F.1, LCO 3.6.1.1 Action B.1, and LCO 3.6.4.3 Action A.1.

It was subsequently determined that the condition nevertheless violated T/S LCO 3.0.4 which does not allow entry into a MODE if an applicable LCO is not met and that SR 3.0.3 could not be applied to this condition to postpone declaring the SSC inoperable during MODE change.

CAUSE OF THE EVENT

The oncoming shift operators assumed the flow paths were operable prior to the Mode change. T/S SR 3.6.1.3.1 and T/S SR 3.6.1.1.2 had been performed satisfactorily and the plant was still bounded within the required TRM frequency.

During turnover between the off-going and on-coming shifts, the verbal turnover was that the system was still aligned for venting and purging, the shift notes correctly indicated that the procedure was still in progress. However, while completion of the vent and purge evolution was not formally entered into the control room log, a note that the containment had been “de-inerted” was entered, the shift turnover checklist incorrectly stated the venting and purging had been secured. Additionally, the place keeping copy of the “in process” venting and purging procedure was not kept in the Equipment Status Log (ESL).

Operators incorrectly assumed that the vent and purge of the Drywell and Torus were completed and that the flow paths were restored to operable by closing the valves in accordance with the venting and purging procedure over the night shift. Thus, when the day shift transitioned into Mode 2 the penetration flow paths immediately became inoperable. The inoperable containment penetration flow paths would also render the one stand by gas treatment train inoperable and primary containment inoperable due to the potential effect of a LOCA.

Crew communication practices provided an inadequate barrier to prevent this event. The turnover checklist contained inaccurate information that remained inaccurate over two shift turnovers. The working copy of the venting and purge procedure was not placed in the equipment status log. Crew awareness of the plant status also contributed to this event. The status of the valve alignment of the penetration flow paths, nor the implication of using the full flow 12 inch diameter SGT ISOL valve instead of the 6 inch diameter valve during the venting and purging evolution was not recognized by the crew. The precautions in the vent and purge procedure regarding the valve lineup with respect to MODES of operation were also not recognized by the crew.

Plant procedures also contributed as an inadequate barrier to prevent this event. While the cold startup checklist did indicate a line item to verify that the full flow SGT ISOL valve is secured, the checklist did not provide a line item for verification of the PCIV's alignment. The assumption is that the current T/S SR remains valid and the SSC's are operable. The checklist is completed over the course of several shifts, and there are no provisions for deviations to be reviewed by the Senior Reactor Operator.

EVENT ANALYSIS

Actual Consequences  There were no significant consequences of this event. The incorrect alignment of the penetration isolation valves with respect to the mode of operation continued to remain bounded by the respective Technical Specifications permitted required actions and required completion times. These time constraints and allowances are based on the safety significance of the SSC being inoperable or removed from service. Therefore, the duration of the condition did not exceed the allowable times that would have been permitted by Technical Specifications.

Potential Consequences This condition has been identified at other BWR plants. It was determined that this valve alignment would create a flow path in the Containment Atmosphere Dilution system that would allow steam released during a potential Loss Of Coolant Accident (LOCA) to bypass the suppression pool torus down comers if the containment isolation valves fail to close. This condition could degrade the pressure suppression function of the suppression pool torus down comers, and possibly over-pressurize the containment. Additionally, even if the containment isolation valves closed as designed during a LOCA there was still the potential to damage the Standby Gas Treatment filters.

EXTENT OF CONDITION

It is presumed that all SSC's are operable and all LCO's are met so long as their T/S SR's are current. The presumption is that any subsequent surveillances, operational evolutions or maintenance activities would not render any previous T/S SR invalid when performed within the T/S SR frequency unless specifically identified to as part of the new activity. In such instances the new activity contains steps to restore the SSC to its previous operable state. The industry presumption is that any SSC is considered operable when bounded by a prior SAT T/S SR that is within its frequency at the time of any mode change. Therefore, while the extent of this condition could be applied to all T/S LCO's required to be met prior to any mode change, it is determined that there are sufficient administrative practices and controls in place to ensure that the probability of similar conditions occurring in the future have been minimized, and that if they do occur they will be identified and remediated within the bounding permitted completion times of the underlying T/S which is based on the safety significance of the inoperable SSC.

  ODSO-4, Shift Turnover and Log Keeping, was revised to require approval of any off normal component position; a review of all shift turnover checklists for accuracy; ensure all in-progress procedures are contained in the equipment status log.

Job performance counseling was held with the operators involved in the incident to reinforce procedural adherence.

The event was presented to all operators to re-enforce the behaviors necessary to ensure that all SSC's are in their respective required configuration for MODE changes.

An evaluation was performed for all licensed operators to verify understanding of Technical Specifications requirements and ability to detect off-normal SSC conditions.

Benchmarked the ENO fleet to identify the best practices for potential procedure changes to ensure correct SSC configuration for MODE change.

Revised ODSO-4, Shift Turnover and Log Keeping, to require panel lineup verification to be completed at least one shift prior to entry into MODE 1, 2, or 3 as a result of the benchmarking activity.

Revised OP-65, Startup and Shutdown Procedure, pre-start checklist to include an item to verify that the pressure suppression function is met as a result of the benchmarking activity.

Performed focused crew assessments for all operating crews with emphasis on teamwork and communication.

Future Actions  Revise the Apparent Cause Evaluation of CR-2012-JAF-08359 to reflect the change in reportability.

ASSESSMENT OF SAFETY CONSEQUENCES  When the penetration flow paths became inoperable, the safety barrier that would normally be created by the valve in the closed position was determined to not be seriously degraded. The criterion for an SSC to be considered seriously degraded applies to the component's material composition. There was no deterioration of the material of the SSC due to metallurgical or chemical reasons, therefore it was concluded that the condition of the barrier did not meet the criteria for being seriously degraded.

The level of significance to safety corresponds to the ability of the SSC to perform its intended design safety function. It was determined that the PCIV's identified in this condition were always capable of meeting their intended design safety function regardless of their open or closed initiating position.

Engineering judgment determined because all of their required sub-systems were operable, because even “normally closed” isolation valves would receive a signal to close during a DBA, and because the valves would be able to close against the dynamic effects of a LOCA it was reasonable to conclude the valves remained operable during the condition and that their miss-alignment with respect to the plant's mode of operation, was a non-conformance that was subsequently corrected within the allowable Technical Specification required action time limits of LCO 3.6.1.3 Action F.1, LCO 3.6.1.1. Action B.1 and LCO 3.6.4.3 Action A.1.

To confirm the impact on nuclear safety a Probabilistic Safety Assessment (PSA) risk significance determination was performed for the Containment Atmosphere Dilution (CAD) system configuration that occurred during this event. The incremental core damage probability (ICDP) is the difference between the configured valves out of position and the baseline core damage frequency (CDF). The ICDP for this event was 3.97E-08 which is within the threshold for normal controls. Therefore this event was insignificant with respect to impact on the CDF.

The Penetration Flow Path, Primary Containment and the Stand-by Gas Treatment train inoperability did not constitute a safety system functional failure as defined by NEI 99-02 Revision 4. The PCIV's were able to perform their intended design safety function from either an open or closed position within their allotted mission time.

Radiological & Nuclear Safety  There were no Radiological or Nuclear Safety concerns associated with this event. The purge system isolation valve closure times facilitate compliance with 10 CFR 100 for offsite radiological consequences. The PCIV's are able to perform their intended design safety function from either an open or closed position within their allotted mission time.

There were no industrial safety concerns associated with this event. The event did not result in a change to plant status or operation.

SIMILAR EVENTS  Cooper Nuclear Station (CNS) Condition Report: CR-CNS-2011-06771 – LCO 3.0.4b not complied with during RE26 Startup. CNS personnel changed modes with equipment in a lineup that conflicted with the T/S requirements. CNS entered MODE 1 with “B” LPCI inoperable. The root cause of the event was a procedural gap that created an error trap in that CNS procedures did not contain steps to require review of all LCO tracking methods to ensure appropriate LPCI configurations prior to entry into MODE 1.

Dresden Nuclear Power Station Unit 2, LER 2003-006-00, dated December 31, 2003, “Unit 2 Purge Valve Open in Conjunction with Drywell Purge Valve in Mode 2”. The condition was reported as a condition that exceeded the allowable times permitted by Technical Specifications for this configuration. The Torus and Drywell vent valves were both open in Mode 2 for a period of 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />. The safety significance of the event was minimal as the vent valves would have closed within 10 seconds during a postulated design basis accident and the calculated containment pressure would have been within its design limits.

Millstone Nuclear Power Station Unit 1, LER 97-039-00, dated November 25, 1997, “Suppression Pool Bypass Path During Purge and Vent Operations”.

The condition was reported as a condition outside the of the plant's design basis. It was discovered during a review of industry events that a valve alignment could exist during primary containment purging which could create a flow path that would allow a steam release during a LOCA to bypass the suppression pool if the inboard containment isolation valves failed to close. This bypass flow path could possibly over pressurize the containment. The root cause was determined to be a design error in that no interlock precluded the bypass flow path nor did the UFSAR caution against this alignment.

Duane Arnold Energy Center, LER 2003-003-00, dated April 20, 2003, “Reactor Mode Change with an LCO in Effect in Violation of Technical Specification 3.0.4”. The condition was reported as any operation or condition that was prohibited by the plant's technical specifications. With the plant in MODE 2 LCO 3.5.1 Condition B was entered for testing, prior to the completion of testing, the Mode switch was taken to MODE 1. The cause of the event, was confusion regarding the “mode of applicability”, operations personnel had incorrectly assumed the prohibition against mode changes were only applicable when transitioning from a mode where T/S LCO's didn't apply to a mode where the T/S LCO's did apply. In other words, they assumed the specified conditions were a collective group. Thus in this case, the mode of applicability for LCO 3.5.1 was Modes 1, 2, and 3, in the operators interpretation, once Mode 2 was entered, LCO 3.0.4. was not applicable to transition from Mode 2 to Mode 1.

Browns Ferry Nuclear Plant Unit 2, LER 2000-001-00, dated July 1, 2000, “Mode Change Not Allowed by Technical Specifications SR 3.0.4 Made During Reactor Startup”. The condition was reported as any operation or condition that was prohibited by the plant's technical specifications. Several TS instrument channel checks were not performed prior to changing from Mode 3 to Mode 2. The channel checks were out of their ordinary 24-hour required frequency. SR 3.0.4 required the channel check SRs be performed prior to entering Mode 2. On discovery of the condition shortly after entering Mode 2, the readings were immediately obtained with no deficiencies identified. The cause of the event was that the operators involved with completion of the SR during startup misinterpreted the TS requirements to mean that the instrument checks applicable in Mode 2 were only required to be documented when in Mode 2.

REFERENCES   JAF Condition Report: CR-JAF-2012-08359, Apparent Cause Evaluation dated 1-28-2013 Revision 1  JAF Condition Report: CR-JAF-2013-01767, Root Cause Evaluation