05000370/LER-2009-001

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LER-2009-001,
Docket Number
Event date: 09-29-2009
Report date: 11-24-2009
Reporting criterion: 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
3702009001R00 - NRC Website
v • d • e

BACKGROUND

The following information is provided to assist readers in understanding the event described in this LER. Applicable Energy Industry Identification [EIIS] system and component codes are enclosed within brackets. McGuire unique system and component identifiers are contained within parentheses.

The low temperature overpressure protection system (LTOP) controls reactor coolant system (NC)[AB] pressure at low temperatures so the integrity of the reactor coolant pressure boundary (RCPB) is not compromised by violating the pressure and temperature limits of 10 CFR 50, Appendix G. The reactor vessel [RPV.] is the limiting RCPB component for demonstrating such protection. The LTOP Technical Specification provides the maximum allowable actuation logic setpoints for the power operated relief valves (PORV)[RV]. The potential for vessel overpressurization is most acute when the NC system is water solid, occurring only while shutdown, when a pressure fluctuation can

  • occur more quickly than an operator can react to relieve the condition.

Technical Specification (TS) 3.4.12, LTOP, provides NC system overpressure protection by limiting coolant input capability and having adequate pressure relief capacity. Limiting coolant input capability requires all but one centrifugal charging pump (NV)[CB][P] or one safety injection pump (NI)[BQ][P] incapable of injection into the NC system and isolating the cold leg accumulators (CLA)[ACC]. The pressure relief capacity requires either two redundant PORVs or a depressurized NC system and an open NC system vent [VTV] of sufficient size. One PORV or the open NC system vent is credited to terminate an increasing pressure event.

Two pumps (two NV pumps, two NI pumps, or combination of one NV and one NI pump) may be capable of injecting into the NC system provided the requirements of TS 3.4.12 Condition A are met. The remaining NV pump and/or NI pump are rendered incapable of injecting into the NC system through removing the power from the pumps by racking the breakers'[52] out under administrative control. An alternate method of LTOP control may be employed by ensuring that two valves [ISV] in the pump discharge flow path are closed.

Engineered Safety Features Actuation Testing Engineered Safety Features (ESF) Actuation testing is performed to demonstrate that each Emergency Diesel Generator (EDG)[DG]has the ability to start and load following a Safety Injection (SI) and/or Blackout (BO) condition as required by Technical Specifications every 18 months. This test is performed in Mode 5 (Cold Shutdown), Mode 6 (Refueling), or No Mode.

During the SI/BO actuation portion of the test, signals are initiated to start the EDG and properly start and sequence the required SI loads (pumps and valves). The ESF test procedure ensures that the required systems have been lined-up, filled, vented, and are operational prior to the start of the test. In addition, the ESF test procedure ensures compliance with the LTOP Technical Specification 3.4.12 regarding the number of NI and NV. pumps that are capable of injecting into the NC system during the test.

EVENT DESCRIPTION

On September 29th, 2009 McGuire Unit 2 was in Mode 6 during the end of cycle 19 refueling outage. Breaker and valve alignments for the 2B ESF test were in progress. The day shift ESF Test Coordinator, an Operations Senior Reactor Operator (SRO), determined that the test alignment would require entering TS 3.4.12, Condition A, two pumps capable of injecting into the NC System, due to the 2A NI pump being racked 'in as the designated Boron Injection Flowpath pump and the ESF test alignment that required the 2B NV pump breaker to be racked in. The required actions were verified and TS 3.4.12 Condition A was

  • entered at 1816 hours0.021 days <br />0.504 hours <br />0.003 weeks <br />6.90988e-4 months <br />. The day shift
  • ESF Test Coordinator alSo recognized that the 2B NI Pump breaker would be racked in but the pump would be incapable of injection due to being double isolated from the NC System.

The day shift ESF Test Coordinator requested a "Lift for Test" to be prepared for 2B NI, 2B NV, and 2B Containment Spray (NS) pump breakers to support the ESF test alignment. The Operations red tagging group prepared the Removal and Restoration (R&R) Lift for Test to remove tags and position each of the breakers to racked in. This Lift for Test was reviewed by the day shift ESF Test Coordinator at 1856 hours0.0215 days <br />0.516 hours <br />0.00307 weeks <br />7.06208e-4 months <br /> and turned over to the night shift ESF Test Coordinator. The night shift ESF Test Coordinator, an Operations SRO, approved the Lift for Test at 2010 hours0.0233 days <br />0.558 hours <br />0.00332 weeks <br />7.64805e-4 months <br />.

At approximately 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br /> two Nuclear Equipment Operators (NEOs) met with the night shift ESF Test Coordinator for a pre-job brief on their assignments for ESF testing. The night shift ESF Test Coordinator briefed the two NEOs on the R&R Lift for Test, two pages of the ESF Test procedure containing alignment steps, and Enclosure '13.2 of the ESF test procedure that double isolated the 2B NI pump prior to racking in the breaker. When the brief was completed, the ESF Test Coordinator asked if there were any questions. One of the NEOs asked if there was any particular order in which the assignments were to be completed, and they received a "no" response.

The ESF Test Coordinator misunderstood the NEO question regarding sequence of the tasks. The NEO asked the question as if it pertained to all the tasks that they had been assigned. The ESF Test Coordinator answered the question as if it only pertained to the ESF test procedure enclosures and not the R&R Lift for Test.

The NEOs proceeded to the field to accomplish their assigned tasks. They aligned two NS valves per the ESF test procedure and then aligned a breaker for the ESF test procedure and racked in the breakers for 2B NI, 2B NV and 2B NS pumps per the R&R Lift for Test. The 2B NI pump breaker was racked in at 2240 hours0.0259 days <br />0.622 hours <br />0.0037 weeks <br />8.5232e-4 months <br />. The NEOs then aligned three more valves per the ESF test procedure, one of which required coordination with Chemistry.

At approximately 2330 hours0.027 days <br />0.647 hours <br />0.00385 weeks <br />8.86565e-4 months <br /> a Unit 2 Reactor Operator (RO) was performing a control board walkdown in preparation for transition to Mode 5. The RO was referencing the Semi-Daily Surveillance PT when a discrepancy with the pump and valve alignments for LTOP was noticed. The 2B NI Pump was racked in and valve 2NI-150B (NI Pump 2B to Cold Leg Injection) and valve 2NI-152B (NI Pump 2B Hot Leg Injection) still had power. The RO understood that power should have been removed from the valves. The RO asked for assistance from the Control Room Supervisor (CRS) to explain the alignment. The CRS contacted the night shift ESF Test Coordinator and questioned the alignment.

The ESF Test Coordinator contacted the NEOs out in the field and asked them if the 2B NI pump breaker was racked in. The NEOs indicated that it was and that the enclosure to double isolate the 2B NI pump had just been started.

The night shift ESF Test Coordinator then directed the NEOs to rack 2B NI pump breaker out and return to the office. The 2B NI pump breaker was racked out at 2358 hours0.0273 days <br />0.655 hours <br />0.0039 weeks <br />8.97219e-4 months <br />.

On September 30 at 0026 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> Problem Investigation Process (PIP) M-09-05948 was generated and the Regulatory Compliance Group duty person was notified and asked to return to the site and support the initial determination of reportability.

the ESF Test Coordinator and the Operations Shift Manager� At approximately 0030 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> the event was discussed with the NEOs, (OSM).

At approximately 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> the ESF test procedure Enclosure 13.2 was completed to double isolate 2B NI pump and the associated : pump breaker was racked in.� It should be noted that the 2B NI pump was single valve isolated at all times which essentially prohibited injection into the NC. system.

At approximately 0700 hours0.0081 days <br />0.194 hours <br />0.00116 weeks <br />2.6635e-4 months <br /> the OSM and Regulatory Compliance determined that an immediate notification to the NRC would not be required because the event did not meet the criteria for "an unanalyzed condition" per 10 CFR 50.72(b)(3)(ii). This was based on the very limited period of time that the breaker was racked in, the fact that the 2B NI pump was always single valve isolated, there was no actual NC system pressure transient, and the NC system was not water solid at the time.

Given that TS 3.4.12, LTOP, allows only two NV or two NI pumps (or combination of one NV and one NI pump) to be capable of injecting into the NC system, this event represented a condition prohibited by Technical Specifications reportable under the requirements of 10 CFR 50.73(a)(2)(i)(B). The balance of the injection sources must have their respective breaker racked out or be double valve isolated from the NC system.

CAUSAL FACTORS

The root cause for this event was that the Removal and Restoration Lift for Test document developed for the ESF test alignment failed to specify the correct sequence for racking in the 2B Safety Injection pump breaker, contrary to the direction provided in the Engineered. Safety Features Actuation Test procedure.

LTOP configuration is usually maintained by racking out and tagging the breakers for the appropriate NI and NV pumps. To perform the ESF test alignment, tags had to be removed from these breakers. A Lift for Test was developed to remove the tags and rack in the breakers for 2B NV pump, 2B NI pump, and 2B NS Pump. The ESF test procedure, PT/2/A/4200/009 B, Enclosure 13.2, double isolates the 2B NI pump prior to racking in its breaker to comply with LTOP requirements. This requirement was not reflected in the R&R Lift for Test.� The interface between the procedure and the R&R Lift for Test was not properly controlled. Without a tie established to the procedure, the R&R Lift for Test did not prohibit racking dn the 2B NI pump breaker prior to double isolation. This resulted in the LTOP Technical Specification violation.

A contributing cause for this event was that the ESF test alignment pre-job brief was inadequate in that it did not communicate proper sequencing of assigned tasks and did not discuss LTOP operating experience.

CORRECTIVE ACTIONS

Immediate:

1. The 2B NI pump breaker was racked out to conform with the LTOP Technical Specification until the double isolation could be performed.

Subsequent:

1. The event was'discussed with Operations personnel.

2. Signage was placed on the Unit 2 NI and NV pump breakers to prohibit racking in the breakers during LTOP unless directed by the appropriate procedure.

Planned:

1.Revise the Safety Tagging process instructions (R&R Lift for Test) to ensure compliance with the LTOP TS 3.4.12 prior to racking in the NI and NV pump breakers (four per unit, eight total) when the plant is in an LTOP condition. In addition, manipulations shall be directed by procedure.

2.Develop and implement signage to place on the NI and NV pump breakers to alert operators that breaker manipulation shall be controlled by procedure when the plant is in an LTOP condition.

3.Incorporate operating experience from this event into the written pre­ job brief for the ESF test alignment.

SAFETY ANALYSIS

There were no adverse safety consequences associated with this event.

This is based on the very limited period of time that the 2B NI pump breaker was racked in and that the 2B NI pump was always single valve isolated. The NI and NV pumps were not operating during this time period. There was no actual NC system pressure transient and the NC system was not water solid at the time such that if a pump had inadvertently started and a valve was inadvertently opened, there would have been ample time for the operators to mitigate the event prior to NC system overpressurization.

The core damage significance (CDS) of this event has been evaluated considering the following:

  • The frequency of events that could lead to an inadvertent operation of 3 injection pumps
  • The failure probability of the operators to secure the pumps following inadvertent operation
  • The failure probability of the single isolation valves
  • The probability of a through wall crack developing given an LTOP event
  • The duration of the LCO non-compliance (less than 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />).

Based on this analysis, this event has a negligible impact on Plant Core Damage Risk. The Core Damage Probability impact is well below 1E-06.

Given the above, this event is considered to be of no significance with respect to the health and safety of the public.

ADDITIONAL INFORMATION

To determine if a recurring or similar event exists, a search of the McGuire PIP database was conducted for a time period covering 5 years prior to the date of this event. Two similar events were identified where R&R related events occurred within Operations.

PIP M-09-0969 Summary:

The Unit 1 Turbine Driven Auxiliary Feedwater (TDCA) pump was inadvertently started on Februry 23, 2009 when Operations,was perforMing a tagout R&R to support solenoid valve modifications. The sequence of the R&R removed power.

from the solenoid valves for the TDCA pump steam supply valves prior to isolating the steam supply. This caused the steam supply valves to fail open and admit steam to the TDCA pump which automatically started the pump.

The root cause for the TDCA pump start event was that the expected behavior to review the "Low Voltage Impact Statement" during the R&R development processes has not been reinforced adequately to ensure consistent performance by the R&R preparer, reviewer and approver. The Low Voltage Impact Statement contained a "warning" stating that the TDCA pump starts due to valves failing open. This root cause is human performance related.

PIP M-09-05201 Summary:

On September 11, 2009, during Unit 2 refueling outage, Condenser Circulating Water (RC) system discharge piping was not properly vented and drained prior to releasing work.

The root cause for the RC system isolation event was a culture regarding the use of Block Tag Out procedures was allowed to exist in which it became an accepted practice to use "procedure steps" in R&Rs to accomplish the evolution rather than using the applicable approved procedures contrary to Nuclear Station Directive requirements.

Conclusion:

The Root Cause for the LTOP Technical Specification violation was how an R&R Lift for Test and a procedure interfaced such that the sequence of events was not controlled.

In PIP M-09-00969, an R&R was sequenced incorrectly because required information was not referenced during R&R development. The TDCA pump start event was similar in that it did involve sequencing, but no procedure interaction existed such that the cause was not the same.

In PIP M-09-05201, an R&R was used as a procedure while an approved procedure was intentionally not used. This was in violation of administrative direction. The RC system isolation event was similar in that " an R&R was involved but there was no intent to interact with a procedure such that the cause was not, the same.

In conclusion, no similar equipment (LTOP) or plant conditions (ESF Testing) existed for any of these events. The causes were not the same for any of the events. Therefore, the LTOP event is similar to the other two events but is determined not to be recurring.

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