IR 05000456/2010010

IR 05000456-10-010 & 05000457-10-010; 08/17/2010 - 09/30/2010; 11/12/2010; Braidwood Station, Units 1 & 2; Special Inspection for the August 16, 2010, Dual Unit Trip and Subsequent Equipment Issues

ML103190505
Person / Time
Site:	Braidwood
Issue date:	11/12/2010
From:	Shear G Division Reactor Projects III
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-10-010
Download: ML103190505 (49)

Text

UNITED STATES ber 12, 2010

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2, NRC SPECIAL INSPECTION TEAM (SIT) REPORT 05000456/2010010; 05000457/2010010

Dear Mr. Pacilio:

On September 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed a Special Inspection at your Braidwood Station, Units 1 and 2, to evaluate the facts and circumstances surrounding the dual unit trip and associated equipment issues that occurred on August 16, 2010. Based on the risk and deterministic criteria specified in Management Directive 8.3, "NRC Incident Investigation Program," and due to the equipment performance issues that occurred, a Special Inspection was initiated in accordance with Inspection Procedure 93812, "Special Inspection." The basis for initiating the special inspection and the focus areas for review are detailed in the Special Inspection Charter (Attachment 2).

The enclosed inspection report documents the inspection results, which were discussed at the public exit meeting on September 30, 2010, with Mr. A. Shahkarami and other members of your staff and on November 12, 2010, with Mr. R. Gaston. The determination that the inspection would be conducted was made on August 17, 2010 and the onsite inspection started the same day.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, interviewed plant personnel, and evaluated the facts and circumstances surrounding the event, as well as the actions taken by your staff in response to the unexpected equipment conditions.

The report documents three self-revealing findings and one NRC-identified finding of very low safety significance. Two of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these issues as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy, dated September 30, 2010. If you contest the violations or the significance of the NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission -

Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Braidwood Plant. In addition, if you disagree with the cross-cutting aspect of a finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Braidwood Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gary L. Shear, Acting Director Division of Reactor Projects Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77

Enclosure:

Inspection Report 05000456/2010010; 05000457/2010010 w/Attachments:

1. Supplemental Information 2. Special Inspection Team Charter 3. Timeline of Events for August 16, 2010, Dual Unit Reactor Trip

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2010010 and 05000457/2010010 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: Braceville, IL Dates: August 17, 2010 - September 30, 2010 Inspectors: J. Jandovitz, Senior Project Engineer DRP M. Thorpe-Kavanaugh, Reactor Engineer, DRP N. Féliz Adorno, Reactor Inspector, DRS T. Go, Health Physics Inspector, DRS Approved by: G. Shear, Acting Director Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000456/2010010;05000457/2010010; 08/17/2010 - 09/30/2010; 11/12/2010; Braidwood

Station, Units 1 & 2; Special Inspection for the August 16, 2010, dual unit trip and subsequent equipment issues.

This report covers an 8-day period (August 17-27, 2010) of onsite inspection and in-office review through September 30, 2010. A four-person team, composed of a project engineer and three regional inspectors, conducted the inspection. Four Green findings were identified, two of them with associated non-cited violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to establish adequate controls to ensure that forebay inspect-and-clean activities provided assurance that systems, structures, and components would be capable of performing their safety function during inspect-and-clean intervals.

Specifically, the inspectors noted that during the event on August 16, 2010, the operability margin of one train of the essential service water system decreased to zero under forebay fouling conditions that were less than the pre-established limiting conditions. The licensee entered this issue into its corrective action program (CAP).

The finding was determined to be more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, forebay conditions would have been allowed to degrade between inspect-and-clean intervals and the potential adverse impact to the essential service water system and its supported equipment was not evaluated. The finding screened as very low safety significance because it was a design deficiency that was confirmed not to result in an actual loss of operability or functionality. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance, decision-making component, because the licensee did not make safety-significant or risk-significant decisions using a systematic process, especially when faced with uncertain or unexpected plant conditions, to ensure safety was maintained. H.1(a) (Section 4OA5.1)

Green.

A self-revealed finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the failure to establish measures for the selection and review for suitability of equipment essential to the safety-related function of the component. In 2008, the safety-related 1.5 ampere (amp) control power fuses in motor control center (MCC) 131X1 were specified to be replaced with 3.0 amp fuses due to failures of other similar 1.5 amp fuses. In 2009, these fuses failed and were replaced with the same sized 1.5 amp fuses, even though the licensees review for suitability concluded the fuses were adequate, but marginally sized. They were then scheduled to be replaced with 3.0 amp fuses in 2015. During the event on August 16, 2010, these fuses failed again at which time they were replaced with 3.0 amp fuses.

The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the failure of these fuses resulted in the loss of function for eight safety injection valves. This caused a train of emergency core cooling and containment isolation for the safety injection system to be inoperable. The inspectors answered "no" to the Mitigating Systems questions and screened the finding as having very low significance (Green). This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program component, because the licensee did not implement corrective actions to address safety issues in a timely manner, commensurate with their safety significance. Specifically, in 2008 these 1.5 amp fuses were specified to be replaced with 3.0 amp fuses, they failed in 2009 and were replaced with 1.5 amp fuses. They were then scheduled for replacement with the higher amp fuses in 2015. [(P.1(d) (Section 4OA5.2)

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance (Green) was identified for the failure to correct a condition that resulted in water being discharged to the turbine building floor during the reject of condensate from the condenser hotwell. Specifically, water had been observed to overflow to the turbine building floor in multiple instances in the past during hotwell condensate reject. However, the licensee did not implement corrective actions to correct this condition or evaluate its impact on plant equipment as required by the licensees corrective action program. The water discharged from the condensate hotwell reject during the Unit 2 trip caused a reactor trip of Unit 1 on August 16, 2010. The licensee entered this issue into its corrective action program and changed the operation of the condensate reject from an automated action to a manual action controlled by the operators.

The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone attribute of configuration control, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability.

The finding screened as very low safety significance (Green) because a Phase 3 evaluation determined that it resulted in a delta core damage frequency of 5.6E-7/year with Large Early Release Frequency (LERF) not being a risk contributor. No violation of NRC requirements was identified because the deficiencies that contributed to the reactor trip were associated with nonsafety-related components. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program component, because the licensee did not have a low threshold for identifying issues and did not identify issues completely. P.1(a)

(Section 4OA5.3)

Green.

A self-revealed finding of very low safety significance was identified for the inadequate evaluation of operating experience done in accordance with the station procedure. Specifically, the licensee evaluated an event at another plant where building material was dislodged during a steam release resulting in a loss of off-site power and concluded the event was not applicable to Braidwood station. The evaluation did not address a previous event at Braidwood where the reactor building flashing was dislodged during a steam release. It did conclude, however, that off-site power could be adversely affected by debris. During the dual unit trip on August 16, 2010, reactor building flashing was dislodged during a steam release and was found on power lines and in the vicinity of the off-site power supplies. The licensee entered this issue into its corrective action program and structurally restrained the flashing left on the reactor building.

The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of protection against external factors and affected the cornerstone objective of limiting the likelihood of those events that challenge critical safety functions during shutdown. Specifically, not protecting the off-site power supplies from flashing falling from the reactor building could result in a loss of off-site power and would challenge the emergency diesel generators to supply alternating current power to safety-related equipment during the plant shutdown. The finding screened as very low safety significance (Green) because it was determined not be a loss of cooling accident or External Event initiator and would not contribute to both a plant trip and the likelihood that mitigation equipment or functions would not be available.

There is no cross-cutting aspect because the 2007 evaluation completed on the operating experience is not reflective of current performance. (Section 4OA5.4)

Licensee-Identified Violations

A violation of very low safety significance identified by the licensee has been reviewed by inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees CAP. This violation and corrective action tracking number are listed in Section 4OA7 of this report

REPORT DETAILS

EVENT DESCRIPTION On August 16, 2010, at 2:06 a.m., the Unit 2 reactor tripped due to a main generator lockout relay actuation. Following the reactor trip, all safety systems functioned as designed, with the exception of one auxiliary feedwater (AFW) flow control valve, which failed open. Additionally, the Unit 2 condenser hotwell rose as expected until it reached the set point to automatically actuate the hotwell condensate reject control valves. This, in combination with the actuation of AFW pumps, resulted in approximately 12,000 gallons of water being discharged from open-ended risers on the AFW suction headers to the turbine building floor on the 451 elevation, where it flowed through holes in the floor and rained down on the lower elevations. Some of this water entered a Unit 1 motor control center (MCC) that contained circuitry for two of the circulating water (CW) pumps.

At 2:19 a.m., as a result of the water in the MCC, the Unit 1 CW pumps A and C tripped, which eventually caused a Unit 1 automatic reactor trip on low condenser vacuum. The water in the same MCC also damaged the instrumentation for the condenser steam dump valves, which then could not be opened for normal decay heat removal. Therefore, operators used the steam generator (SG) power operated relief valves (PORVs) to relieve decay heat and maintain Unit 1 temperature and pressure. In addition, the main steam safety valve (MSSV) 1D opened and would not close as expected.

A detailed timeline of the dual unit trip is contained in Attachment 3.

Inspection Scope A Special Inspection was initiated following the NRCs review of the deterministic and conditional risk criteria specified in Management Directive 8.3. The inspection was conducted in accordance with NRC Inspection Procedure (IP) 93812, Special Inspection, and the Special Inspection Charter, dated August 16, 2010 (Attachment 2). The team gathered information from the plant computer and event recorder with alarm printouts; interviewed station personnel; performed physical walkdowns of plant equipment; reviewed procedures, maintenance records and various technical documents; and reviewed corrective action documents and causal evaluations. A list of specific documents reviewed is provided in Attachment 1.

4OA5 Other Activities - Special Inspection

Sequence of Events

a. Inspection Scope

The team evaluated the licensee's initial response to the event, focusing on relevant plant conditions, system line-ups, and operator actions. This evaluation included a review of the control room operators' use of operating procedures and identification of degraded plant conditions. The team interviewed plant personnel and reviewed applicable portions of the emergency operating procedures (EOPs), control room logs, plant event recorder data, and corrective action program (CAP) documents.

A detailed sequence of events is included in Attachment 3.

b. Findings and Observations

No findings of significance were identified.

Licensees Event Response for Unit 1 Trip

a. Inspection Scope

The team reviewed the licensees plans and actions for assessing the impact that the event had on Unit 1 systems. The review included discussions with various site engineers, review of action plans for evaluating the condition of systems and components that did not perform as expected, review of in-process results from the licensees reviews, and methods for tracking identified deficiencies. In addition, the team independently reviewed the licensees post-trip review to determine the cause of the Unit 1 reactor trip and whether it was a manual or automatic reactor trip including a review of plant data and records to confirm the adequacy of the licensees assessment and planned corrective actions. The team also reviewed the licensees assessment of their readiness to restart Unit 1 and independently assessed the restart schedule and readiness.

b. Findings and Observations

No findings of significance were identified.

Licensees Event Response for Unit 2 Trip

a. Inspection Scope

The team reviewed the licensees plans and actions for assessing the impact of the event on Unit 2 systems. The review included discussions with various site engineers, review of action plans for evaluating the condition of systems and components that did not perform as expected, review of in-process results from the licensees reviews, and methods for tracking identified deficiencies. In addition, the team independently reviewed the licensees post-trip review to determine the cause of the Unit 2 reactor trip, whether it was a manual or automatic reactor trip, including a review of plant data and records to confirm the adequacy of the licensees assessment and planned corrective actions. The team also reviewed the licensees assessment of their readiness to restart Unit 2, and independently assessed the restart schedule and readiness.

b. Findings and Observations

No findings of significance were identified.

Assessment of Operators Performance

a. Inspection Scope

The team evaluated the operators response and performance during the events, including awareness of and response to plant conditions and shutdown activities. This evaluation included interviews of all members of the operating crew who responded to the initial event, review of the control room operators' use of EOPs, identification of degraded plant conditions, initial actions to mitigate the event, and significant limiting condition for operation (LCO) entries. Additionally, this evaluation included performing walk-downs of the plant, and reviewing operator logs, annunciator response procedures, plant drawings, plant process computer data, and CAP documents.

b. Findings and Observations

Operations response to the dual unit shutdown was considered generally good, however, the following observations were noted.

• Unit 1 water box isolation was not completed in accordance with the guidance provided in the alarm response procedure. Specifically, the alarm response procedure stated that boxes A and D should not be isolated if possible.

However, these were the two water boxes isolated by operators. The team considered this important because the loss of condenser vacuum increased significantly and unexpectedly when the water boxes were isolated. The team verified that, during a transient, the conduct of operations procedures allowed operators to not immediately refer to the alarm response procedure. Also, the licensee used the simulator to verify that isolating water boxes A and D instead of water boxes B and C had no effect on the condenser vacuum, and therefore no real impact on the event. To better control the condenser vacuum, the licensee alarm response procedure was enhanced to not isolate any of the water boxes.

Since the procedures allowed the operators to perform the actions taken, there was no violation of NRC requirements;

• Unit 1 operators missed an entry into an LCO for Technical Specification (TS)

Section 3.3.9, regarding boron dilution actions for greater than the TS allowed action statement time (discussed as a licensee-identified non-cited violation in Section 4OA7); and

• The Unit 1 MSSV 1D opened and did not close as designed, causing a continuous steam release to the environment and an unexpected contribution to the cooldown rate. The team noted that the operators were not aware that the safety valve was stuck open until notified by a responder, who arrived from offsite about 40 minutes after the event started. There was no indication in the control room for the operation of the MSSVs. The team noted that the status of the safety valves was important to understanding plant conditions and controlling the plant cooldown. This issue was entered into the licensees corrective action program as AR01101893.

Major Equipment Problems

a. Inspection Scope

The team evaluated the circumstances surrounding the following major equipment problems associated with the August 16, 2010, event:

• Unit 2 main generator lockout relay actuation;

• MCC 133V failure due to water intrusion;

• Unit 2 AFW flow control valve (FCV) (2AF005H) failure to open;

• Unit 1 MSSV failure to remain fully seated following the reactor trip;

• Unit 1 condensate/condensate booster (CD/CB) pump C seal failure;

• Unit 1 essential service water (SX) high differential pressure condition following the Unit 1 reactor trip; and

• Unit 1 blown fuses identified while placing the unit on shutdown cooling.

The team performed walk-downs of these components and conducted interviews of plant personnel. In addition, the team reviewed engineering evaluations, procedures, operator logs, and equipment history. While assessing the licensees performance in addressing these issues, the team considered cause determinations, planned corrective actions, prior similar events, adequacy of past corrective actions, adequacy of the licensees extent of condition reviews, and adequacy of past operability reviews.

b. Findings and Observations

Unit 2 main generator lockout relay actuation: The Unit 2 trip was caused by the main generator stator ground system due to a ground fault. Complex troubleshooting was performed in accordance with Licensee Procedure MA-AA-716-004 associated with Issue Report (IR) 1101855 and concluded that the cause of the fault was from pieces of a failed de-ionizing damper. This damper provides cooling to ducting for the main generator bus work. The team reviewed the history of the dampers, including previous inspection results from 2002, performed in response to operating experience, and noted that these dampers were next scheduled for inspection during the Spring 2011 outage, in accordance with their preventive maintenance (PM) schedule. The team verified that the licensee had revised the PM schedule to perform more frequent inspections of these dampers. No findings were identified.

MCC 133V failure due to water intrusion: The Unit 2 trip caused water to be discharged from the Unit 2 auxiliary feedwater suction header stand-pipes to the turbine building floor and lower levels. Water from the 451 elevation travelled through openings in the floor to the 426 elevation landing on the MCC 133V and transformer. The water intrusion into the MCC caused breaker 1435VU to experience an overcurrent trip, resulting in the de-energizing of non-safety related buses 133U and 133V, as well as the associated MCCs 133U and 133V.

The team reviewed the licensees immediate actions and troubleshooting activities and performed a walkdown of the affected areas. The licensees short-term corrective actions were to install a temporary modification allowing MCC 133V to be powered from the 133Z transformer, with permanent replacement of the transformer scheduled for the next refueling outage. The inspectors reviewed the temporary modification and contingency plan for repowering MCC 133V using the MCC 133Z transformer.

The inspectors questioned the extent of condition of the water intrusion on the Unit 2 equivalent MCC 233V and verified that the licensee had completed an inspection of MCC 233V. The immediate inspections identified water in the vicinity of MCC 233V, but no damage was found after additional visual inspections into the transformer cabinet.

The inspectors also reviewed the operational technical decision-making document for the continued operation of MCC 233V. Additionally, the team reviewed the results of the last performed preventative maintenance inspections for these MCCs. No findings were identified.

Unit 2 auxiliary feedwater flow control valve (2AF005H) failed open: The function of AFW flow control valve 2AF005H was to control AFW flow to the steam generator (SG).

This air-operated valve was normally open and fails open in the event of a loss of air to the valve operator. The valve was designed to fail in the open position to ensure the delivery of AFW flow to the SGs to cool the reactor down safely to the temperature at which the residual heat removal system could be utilized. The consequence of this failure was an increased flow rate. To prevent SG high level, the operators throttled the AFW isolation valve to maintain the desired flow rate following alarm response procedure BwAR 1-3-B7, AF pump discharge flow high. The team noted that the current SG tube rupture analysis and faulted SG analysis assumed that all the AFW control valves fail open. Specifically, Section 15.2.8.2 of the Updated Final Safety Analysis Report (UFSAR) stated that the case in which the valves fail open had also been considered because air supply to these valves was not safety-related. It further stated that flow may be diverted out of the break, but more flow may be provided to the intact SGs at lower pressure. The safety analysis found this case to be less limiting and gave credit for operators to isolate the faulted generator 20 minutes after the reactor trip.

The licensees troubleshooting of the failure of the valve 2AF005H found that both the control loop and valve were functioning properly per their design with no anomalies noted. The licensee determined that the most likely cause of the valve failure from their troubleshooting efforts was test switch problems on a card used to defeat the control logic during calibration activities such that the valve did not stroke. The licensee determined that it was likely that the card relay contacts did not remake the normal current path following the most recent calibration. Since the failure mode was in the fail safe condition, valve fails open, operability of the system was not affected. It was also postulated that the open relay contacts subsequently made up when the card relay was cycled by placing the normal/defeat switch to defeat and then back to normal when performing the troubleshooting activities. This was the likely explanation of why no problem was found during the troubleshooting. As a result, the licensee replaced the card and sent the suspected failed card to a laboratory for further evaluation.

The team reviewed the AFW control valve health history and did not find a prior similar issue. However, when assessing the licensees initial extent of condition, the team noted that the licensee focused on the other AFW control valves and did not consider other applications that use similar cards. In response to the teams observation, the licensee indicated that these other applications will be evaluated as part of the apparent cause investigation. No findings were identified.

Unit 1 MSSV that did not remain fully seated following the reactor trip: After the Unit 1 reactor trip, MSSV (1MS016D) opened in response to overpressure but did not reseat as designed. This event was significant in that the steam release from this MSSV contributed to the tritium release discussed later in this report. In addition, the MSSV must meet the operability requirements contained in TS Sections 3.6.3., Containment Isolation, and 3.7.1, Main Steam Safety Valves.

Following the event, the valve was replaced with a spare and the MSSV that remained open was sent to a testing facility for diagnosis. The results from the testing facility were not available when the special inspection ended. Therefore, this issue continues to be followed by the resident staff as the licensee finalizes their conclusions and resultant corrective actions. This was entered into the licensees corrective action program as AR01101893.

The team noted that the Unit 1 operations staff had not identified that the MSSV was open until an individual arriving from offsite to support the event mentioned it to the control room operators. This was about 40 minutes after the start of the event. There is no indication in the control room for the status of any of the MSSVs. Since the open MSSV did not adversely affect the cooldown of the unit, did not significantly contribute to the tritium release, or cause the inoperability of any safety-related equipment, no performance deficiency was identified. No findings were identified.

Unit 1 C CD/CB pump seal failure: During the Unit 1 trip, the CD/CB pump 1C automatically started as designed. Approximately 45 minutes later, operators secured the pump due to a shaft seal failure. After the pump was disassembled on August 19, 2010, the impeller wear rings were found shattered. The licensee was not successful in retrieving all the pieces from the failed wear ring and concluded that they were within the piping systems. A loose parts evaluation was completed as part of IR 1103277. The team also noted that the CD/CB pump 1B failed in the same manner on August 20, 2010. All the broken pieces were not retrieved. Engineering evaluation EACE 00789519-04 identified that all CD/CB pump impellers were susceptible to stress corrosion cracking and were scheduled for inspection and replacement. AR00837434 recommended replacement of the C CD/CB pump impeller during the system outage during the week of January 3, 2011.

Regarding the unaccounted for seal pieces in the system piping, the plant is designed with screens in the FW pump suction piping that prevent loose parts from entering the SGs, which protect the integrity of the primary pressure boundary of the SG tubes.

These screens are inspected periodically to ensure they are intact and to remove any parts that may have been collected. The team verified that the screens were intact through review of previous inspection results. The flows in the condensate system would not be sufficient to allow the loose parts to travel to these screens until after start-up. Therefore, additional inspection of these screens integrity and for CD/CB wear ring pieces will be conducted by the licensee as part of their scheduled maintenance activities. No findings were identified.

Unit 1 SX high differential pressure condition following the Unit 1 reactor trip: The SX is designed to ensure that sufficient cooling capacity is available to provide adequate cooling during normal and accident conditions. The system includes a strainer downstream of the SX pumps to protect downstream components from fouling (e.g.,

heat exchanger tube blockage). Differential pressure is measured across the strainer to monitor strainer fouling conditions. The strainer is automatically backwashed when the differential pressure reaches its high setpoint.

The team determined that the backwash feature of the SX system performed as designed during the event of August 16, 2010. In addition, the team confirmed that the high differential pressure experienced during the event did not cause or indicate inoperability of the SX system. Specifically, the SX system was confirmed to have a discharge header pressure value equal to the operability limit value established by the most recent flow balance of the system. However, the team noted that the forebay conditions present during this event were less limiting than the conditions considered acceptable by the licensee and was determined to be a finding as discussed below.

.1 Forebay inspect-and-clean activities did not ensure that structure, systems, and

components will be capable of performing their safety function:

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to establish adequate controls to ensure that forebay inspect-and-clean activities provide assurance that structure, systems, and components (SSCs) will be capable of performing their safety function.

Description:

On August 20, 2010, the inspectors noted that the licensee had not established adequate controls to ensure that future forebay inspect-and-clean activities provide reasonable assurance that SSCs will be capable of performing their safety function during inspect-and-clean intervals. Specifically, the inspectors noted that the operability margin of the SX system decreased to zero under forebay fouling conditions that were considered less than the pre-established limiting conditions developed by the licensee.

The licensee developed and implemented a lake macro-biological program as a corrective action to NCV 05000456/2009003-07; 05000457/2009003-07 for the 2008 bryozoa infestation event at the screenhouse forebays, which are the water intake structures on the lake, documented in NRC Inspection Report 05000456/2009003; 05000457/2009003. The lake macro-biological program included alert and action levels for fouling accumulation in the forebays. If the alert level is reached, the licensee is required to notify the heat exchanger coordinator and CW system engineer to determine if cleaning efforts are necessary. If the action level is reached, the licensee is required to clean, evaluate for extent of condition, and generate an IR in the CAP.

During the 2010 Unit 1 trip, the loss of bus 133V resulted in the loss of CW pumps 1A and 1C and the failure of their associated discharge valves in the open position, causing reverse flow to the 1A and 1C forebays. The reverse flow caused high flow conditions in normally low flow areas where bryozoa and loose debris accumulate. This abnormal flow caused the bryozoa to be suspended and flow into the SX system. The amount of material entering the SX system affects the performance of the system, in particular the water pressure in the SX header. The inspectors noted that the licensees forebay fouling program was based on the 2008 bryozoa infestation experience and that it did not consider the debris removal and transportation mechanism associated with CW reverse flow even though it was mentioned in engineering change (EC) 373358, Bryozoan event technical evaluation supporting SX availability.

The licensee uses SX discharge header pressure as the main factor in determining operability of the SX system and SX supported systems. Specifically, the SX system was flow balanced by throttling various SX valves such that the necessary flows to all post-accident SX heat loads were achieved. Operability was maintained as long as the header pressure remained at or above the recorded SX header pressure value at the time of the flow balance. The operability of the reactor containment fan coolers (RCFCs)was most sensitive to SX header pressure because it was the only SX supported system with an associated TS flowrate value (i.e., TS 3.6.6, Containment Spray and Cooling Systems). The SX header pressure was relied upon by the licensee as the indicator of the reactor containment fan coolers flowrate.

The inspectors noted that the IRs that captured the as-found conditions of the 2010 inspect-and-clean activities did not adequately screen for operability and extent of condition. For example, AR0109291 identified EC 376317, CW forebay inspection acceptance criteria for bryozoa accumulation, as the document that established the most conservative limits. EC 376317 allowed a maximum accumulation of 30 inches of bryozoa in any location, using a 3 inch per week accumulation rate. Based on the results of the 1C forebay inspection performed on August 6, 2010 and EC 376317, the 1A forebay would have had bryozoa spots of 15 inches maximum height mostly at the walls and minimum fouling on the floor during the dual reactor trip that occurred on August 16, 2010. However, during the reverse flow conditions and amount of debris experienced during this event, Unit 1 SX discharge header pressure operability margin decreased to zero. Therefore, the inspectors concluded that 30 inches of bryozoa in any location was not an adequate criterion to ensure that SSCs will be capable of providing their safety function.

Analysis:

The inspectors determined that the failure to establish adequate controls, which ensure that future forebay inspect-and-clean activities provide assurance that SSCs will be capable of performing their safety function during inspect-and-clean intervals, was contrary to procedure ER-AA-340, GL 89-13 Program Implementing Procedure, and was a performance deficiency.

The performance deficiency was determined to be more than minor because, if left uncorrected, could potentially lead to a more significant safety concern. Specifically, unacceptable forebay conditions would have been allowed between inspect-and-clean intervals and potential adverse impact to the SX system and its supported equipment would not be evaluated. Therefore, SSCs could be incorrectly determined to be operable, and appropriate corrective actions to ensure that SSCs will be capable of performing their safety function would not be implemented. The inspectors concluded that this finding was associated with the Mitigating System Cornerstone.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of findings, Table 4a for the Mitigation Systems Cornerstone. The finding screened as very low safety significance (Green)because the finding was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, it was determined that the worst case condition since implementation of the corrective actions of the 2008 event was August 2010. During the August 2010 dual reactor trip, Unit 1 lost two CW pumps, resulting in debris entrainment into the SX system, which did not cause the SX discharge header pressure value to drop below operability limits.

The inspectors determined that this finding had a cross-cutting aspect in the area of human performance decision-making component, because the licensee did not make safety-significant or risk-significant decisions using a systematic process to ensure safety was maintained, especially when faced with uncertain or unexpected plant conditions. Specifically, the licensee did not use a systematic process to ensure that SSCs would not be adversely affected by fouling at the forebays between inspect-and-clean intervals because debris removal and transport mechanisms were uncertain.

H.1(a)

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure ER-AA-340 required the licensee to perform tests or inspections at intervals that provide assurance that the equipment is capable of performing its safety function during the interval.

Contrary to the above, before August 20, 2010, the licensee did not follow Procedure ER-AA-340. Specifically, the licensee did not establish adequate controls to ensure that future forebay inspect-and-clean activities provide assurance that SSCs will be capable of performing their safety function during inspect-and-clean intervals. Because this violation was of very low safety significance and it was entered into the licensees CAP as AR01106410, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2010010-01; 05000457/2010010-01, Forebay inspect-and-clean activities did not ensure that SSCs will be capable of performing their safety function)

The licensee captured this issue in their CAP and corrective actions considered at the time of this inspection were procedure changes and margin improvements.

Unit 1 blown fuses identified while placing the unit on shutdown cooling: On August 16, 2010, the plant attempted to align Unit 1 for shutdown cooling after the reactor trip. Due to blown control power fuses on MCC 131X1, eight safety injection (SI) valves could not be energized, one of which prevented the realignment to hot leg recirculation for the 1A SI train and from the 1A and 1B Residual Heat Removal (RHR)trains. Train A of the Emergency Core Cooling System (ECCS) was declared inoperable and LCO 3.5.2, ECCS Operating, was entered. In addition, two of the SI valves were containment isolation valves and the blown fuse prevented closure.

Therefore, LCO 3.6.3, Containment Isolation was entered. The fuses were replaced within time specified by the TS LCO action statement. The team reviewed the history of these control power fuses and found these fuses had been identified as undersized or marginally sized in 2007 and had failed in 2009.

.2 Failure to replace low margin fuses in MCC131X1:

Introduction:

A self-revealed finding of very low safety significance (Green) and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the failure to establish measures for the selection and review for suitability of equipment essential to its safety-related function. Specifically, in 2008, the safety-related 1.5 amp control power fuses in motor control center (MCC) 131X1 were identified to be replaced with 3.0 amp fuses due to failures of other similar 1.5 amp fuses. In 2009, these fuses failed and were replaced with the same size 1.5 amp fuses.

The subsequent licensee evaluation concluded the fuses were adequate but marginally sized. During the event on August 16, 2010, these fuses failed again at which time they were replaced with 3.0 amp fuses.

Description:

On August 2, 2007, apparent cause evaluation (ACE) 00664657 was performed when the 1.5 amp control power fuses in MCC 234V6 E1 failed. The ACE concluded these control power fuses were undersized/marginally sized. A review of historical data associated with MCC control circuits having 1.5 amp fuses found similar failures. The ACE determined this condition would apply to all 480Vac MCCs with primary connected size 3 NEMA contactor starters with 1.5 amp primary control power fuses. Assignment 14 of the associated AR identified the fuses in MCC 131X1 1AP21E-M2AP, Feed to ECCS Water Supply Isolation Valves, were vulnerable to this condition.

On June 3, 2008, EC 370955 was completed and determined that it was acceptable to increase the primary side control circuit KTK-R-1-1.5 (1.5 amp) fuses, with Bussman KTK-R-3 fuses (3 amp). This would allow for operating margin while still providing protection and coordination.

AR782761 specified replacement of the 1.5 amp control power fuses in MCC 131X1 1AP21E-M2; feed to ECCS water supply isolation valves with 3.0 amp fuses. This replacement was scheduled for A1R14 (2009).

On May 28, 2009, operators noted that the indication for the 480 volt feed to Bus 131X1A/X2A (MCC 131X1/X2) was open. It was determined that this was due to the failure of the 1.5 amp control power fuses in MCC 131X1 Compartment M2. This affected the operability of eight SI valves in the A train and would have prevented the realignment to hot leg recirculation for the SI train 1A from the residual heat removal trains 1A and 1B. However, the ability to provide flow to hot leg trains 1B and 1C via the SI pump 1B was unaffected. This resulted in entry into Technical Specification LCO 3.5.2, conditions A and B, for loss of ECCS functions and also TS LCO 3.6.3, condition A, for the loss of power to two SI containment isolation valves. Operations replaced the 1.5 amp fuse with another 1.5 amp fuse to exit from the respective LCOs.

During the investigation and evaluation of the failure of the fuses on May 28, 2009, conducted under AR925143, the licensee concluded the fuses were adequate, but had low margin and did not question whether the currently installed fuses should be promptly replaced with the 3 amp fuse in accordance with the previous evaluations and recommendations. The inspectors also noted the fuses were replaced by operations personnel under their fuse replacement program, which is not mentioned in the AR.

Instead, the AR referenced work order (WO) 1239369 for replacement of the fuses in 2009, but it was discovered that no work was done under this WO even though it indicated that it was completed. Also, after the fuse was sent to the laboratory for analysis, the laboratory report concluded that the fuse blew from an overload condition, which supported the view that the fuses were marginally sized. Additionally, licensee personnel indicated the failure was caused by not performing preventative maintenance (PM) activities as planned/scheduled, and referenced the EC to replace the fuses with a 3 amp fuse. In spite of this information, the licensee did not schedule the fuses to be replaced with the 3.0 amp fuses until 2015. Therefore, the inspectors concluded the licensee had not establish measures that resulted in an adequate selection and review for suitability of the 1.5 amp fuses to perform their safety-related function.

During the event on August 16, 2010, these fuses failed again, at which time they were replaced with 3.0 amp fuses.

Analysis:

The inspectors determined that the failure to establish measures for the selection and review for suitability of equipment essential to its safety-related function was a performance deficiency. Specifically, in 2007, ACE 664657 identified that the 1.5 amp fuses in MCC 131X1 may be undersized or marginally sized and should be replaced with 3.0 amp fuses. In 2009, these fuses failed and the licensees review for suitability concluded the fuses were adequate but marginally sized and replaced the fuses with the same size 1.5 amp fuses. In 2010, these fuses failed again after which the 3.0 amp fuses were installed.

The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of these fuses resulted in the loss of function for eight SI valves related to ECCS and containment isolation functions.

The inspectors determined that the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Mitigation Systems Cornerstone. The inspectors answered "no" to the Mitigating Systems questions and screened the finding as having very low significance (Green). This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program component, because the licensee did not take corrective actions to address safety issues in a timely manner, commensurate with their safety significance. Specifically, these 1.5 amp fuses were identified in 2007 as undersized or marginally sized, they failed in 2009 and were replaced with the same size fuse, and then scheduled for replacement with the 3.0 amp fuses in 2015. [(P.1(d).

Enforcement:

10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related function of structures, systems, and components.

Contrary to the above, on or before August 16, 2010, the licensee had not established measures that resulted in an adequate selection and review for suitability of the 1.5 amp control power fuses in MCC X1A to perform their safety-related function. Specifically, in 2008, AR782761 specified these fuses should be replaced with 3.0 amp fuses. In May 2009, the fuses failed and were not replaced with 3.0 amp fuses even though the licensees review for suitability determined the fuses were adequate but had low margin.

After the failure in 2010, the fuses were replaced with 3 amp fuses and the licensee was conducting an evaluation of the fuse replacement schedule for all similar fuses.

Because this violation was of very low safety significance and it was entered into the licensees CAP as AR1106401, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2010010-02, Failure to replace marginally sized fuses in MCC131X1).

Unit 2 Auxiliary Feedwater Suction Vent Riser

a. Inspection Scope

The team reviewed the circumstances surrounding the water on the turbine building floor from the Unit 2 auxiliary feedwater suction header stand-pipes and assessed the licensees performance in addressing this issue. Specifically, the team reviewed:

• measures used to control the water when it is spilled onto the floor;

• any historical issues with water spilling from this and the Unit 1 vent; and

• the adequacy of the AFW suction header stand-pipe design.

The team performed walkdowns of the plant and conducted interviews of plant personnel. In addition, the team reviewed engineering evaluations, procedures, operator logs, drawings, and equipment health history.

b. Findings and Observations

The AFW suction header includes two stand-pipes (or vent risers) used to attenuate AFW pumps suction pressure transients during pump startup by providing a source of water that is close to the pumps suction and at a head equal to the water height in the condensate storage tank (CST). The CST is the preferred source of water to the AFW pumps. These transients occur because the motor-driven AFW pump accelerates at a higher rate than the water coming from the CST resulting in a temporary low suction pressure (assuming that the stand-pipes were isolated from the header). The high point on the stand-pipes is approximately 8.5 feet higher than the top of the CST. When the condenser hotwell high level setpoint is met, the hotwell overflow control valves open to transfer condensate reject to the CST via the condensate header using the CD/CB pumps. The condensate header communicates with the AFW suction header coming from the CST. When the flow rate of water rejected from the hotwell to the CST is greater than the discharge rate out of the AFW pumps, the level in the standpipe would increase and the conditions were great enough that water could spill onto the turbine deck, because the stand-pipes are open to the atmosphere on the common turbine building at the 451 elevation. The discharged water is able to flow through the floor and rain down the lower elevations through multiple openings in the floor. The team found that this occurrence was known to happen in multiple occasions in the past by the licensee without significant impact to the plant. However, on August 16, 2010, this occurrence caused the trip of Unit 1. As a result, one self-revealed finding of significance was identified, as discussed below.

.3 Failure to identify and correct water discharged to the turbine building floor during

condensate reject

Introduction:

A self-revealed finding of very low safety significance was identified following a dual unit trip on August 16, 2010. Specifically, the licensee failed to identify and correct a condition that resulted in condensate reject (i.e. water) to be discharged to the turbine building floor. This condition resulted in Unit 2 having caused a reactor trip of Unit 1.

Description:

On August 25, 2010, the inspectors noted that the licensee failed to correct a condition that resulted in water to be discharged from Unit 2 to the common turbine building floor during reject of condensate from the Unit 2 condenser hotwell, which led to the reactor trip of Unit 1 on August 16, 2010.

When Unit 2 tripped on August 16, 2010, the condenser hotwell level began to rise and reached the setpoint to actuate hotwell overflow control valves. For approximately 15 minutes, the flow rate of water rejected from the hotwell to the CST was greater than the discharge rate out of the AFW pumps. Therefore, during this time, water was discharged from the two Unit 2 AFW stand-pipes to the turbine building floor at the 451 elevation. The turbine building is shared between the two units. The licensee roughly estimated that 12,000 gallons of water discharged through the stand-pipes. This volume of water flowed down onto the lower elevations of both units through nearby floor openings.

Photograph 1 - One of two Unit 2 suction header stand-pipes Water entered MCC 133V and caused feed breaker 1435V to trip. The loss of MCC 133V resulted in the loss of 1A and 1C CW pumps, which led to a Unit 1 automatic reactor trip on low condenser vacuum approximately 13 minutes after Unit 2 tripped.

The inspectors learned through interviews and discussions with plant personnel that water had been observed to discharge through the AFW stand-pipes on multiple occasions in the past. However, this occurrence was found to be captured in the CAP only on one occasion in 2009. In addition, the inspectors noted that the resolution of the issue captured in 2009 focused only on industrial safety and did not evaluate the impact of the water on plant equipment. This condition had not caused a reactor trip prior to the 2010 event.

Procedure LS-AA-120, Issue identification and screening process, required that conditions adverse to quality (CAQ) be captured in the CAP, evaluated for significance following the guidance contained in Attachment 2 of the procedure, and assigned an investigation class following the guidance contained in Attachment 3. Attachment 2 stated that a near-miss condition that, under different circumstances would reasonably be expected to result in a significance level 1 or 2 event, is an example of a significance level 3 CAQ. A reactor trip was identified as a significance level 2 event by this attachment. The guidance for assigning an investigation class contained in 3 considered two elements associated with the cause of the CAQ: risk and uncertainty. It stated that risk involves consequence and probability of recurrence. In determining the potential consequence, the guidance considered not only what happened but also what could have happened if the circumstances were different. That is, if under different circumstances a more significant event could have occurred, then the potential consequence may be higher. Following the guidance contained in s 2 and 3 of the procedure, the inspectors determined that the condensate reject overflow observed in the past would have been screened as a high risk significance level 3 CAQ. According to Procedure LS-AA-120, a high risk CAQ receives at least an ACE and assignment of corrective actions to restore the CAQ to an acceptable condition. Procedure LSAA-125, Corrective action program procedure, defined corrective action as an action taken or planned that restores a CAQ to an acceptable condition. It further required creating a corrective action to restore a CAQ.

However, the inspectors found that the licensee did not create a corrective action to restore the CAQ that resulted in condensate reject overflow to the turbine building floor to an acceptable condition.

The licensee captured this issue in their CAP as AR01106403. The corrective actions included changing the normal position of the manual valves downstream of the hotwell overflow control valves to the close position. In this configuration, manual action will be required to reject water from the hotwell by operating the normally closed bypass valve.

The intent is to reject water in a controlled fashion. Continuous monitoring at the AFW stand-pipes will determine if water is being discharged to the turbine building while performing this action and prevent excessive discharge to the floor.

Analysis:

The inspectors determined that the failure to correct a condition that resulted in water to be discharged to the turbine building floor during reject of condensate from the condenser hotwell was contrary to Procedure LS-AA-125 and was a performance deficiency. This condition led to a reactor trip.

The performance deficiency was determined to be more than minor because it was associated with the Initiating Events Cornerstone attribute of configuration control and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability. Specifically, water discharged to the turbine building floor during reject of the condensate from the Unit 2 condenser hotwell caused component failures that led to a reactor trip on Unit 1.

The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Initiating Events Cornerstone. The inspectors answered Yes to the screening question Does the finding contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions will not be available?, since the condenser steam dump valves are listed as mitigation equipment in the Phase 2 Risk-Informed Inspection Notebook for Braidwood Station.

Therefore, a Phase 2 SDP evaluation was performed using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations.

Using the SDP Phase 2 Worksheets, the performance deficiency was evaluated to increase the frequency of a transient initiating event (i.e., TRANS, Table 3.1) due to a loss of condenser heat sink. Section 1.2 of IMC 0609, Appendix A, Attachment 2, Site Specific Risk-Informed Inspection Notebook Usage Rules, states that if the increase in the frequency of an initiating event due to an inspection finding is not known then the Initiating Event Likelihood (IEL) for the applicable initiating event needs to be increased by one order of magnitude. Applying an increase in the IEL by one order of magnitude to the TRANS initiating event resulted in a characterization of the finding as White in Phase 2. Since this characterization was considered to be conservative, a Phase 3 SDP evaluation was performed.

The Senior Reactor Analysts (SRAs) evaluated the finding using the Braidwood Standardized Plant Analysis Risk (SPAR) Model Revision 3P (Change 3.51). The SRAs increased the Loss of Condenser Heat Sink (LOCHS) IEL from its nominal value of 8.0E-2/year to account for the performance deficiency as an additional contributor to the nominal IEL. Applying an increased IEL in the Braidwood SPAR model resulted in a delta Core Damage Frequency (CDF) of 5.6E-7/year due to the performance deficiency. Large Early Release Frequency (LERF) was not a risk contributor based on LERF factors in the Risk-Informed Inspection Notebook being zero for transient with loss of condenser heat sink. Based on the Phase 3 analysis, the inspectors determined that the finding was of very low safety-significance (Green).

The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee did not have a low threshold for identifying issues and did not identify issues completely. Specifically, the condition was captured in the CAP on only one occasion in 2009 while condensate reject had been observed to overflow to the turbine building floor in multiple instances in the past.

In addition, the licensee did not fully evaluate the issue in 2009 because the licensee failed to recognize that the issue had the potential to cause a reactor trip. P.1(a)

Enforcement:

No violations of NRC requirements were identified because the affected components were not safety related. Because this finding does not involve a violation and has very low safety significance, it is identified as a finding.

Corrective actions for this event included changing the normal position of the manual valves downstream of the hotwell overflow control valves to the closed position. In this configuration, manual action will be required to reject water from the hotwell by operating the normally closed bypass valve. The intent is to reject water in a controlled fashion.

Continuous monitoring at the AFW stand-pipes will determine if water is being discharged to the turbine building while performing this action.

(FIN 05000456/2010010-03; 05000457/2010010-03, Failure to identify and correct water discharged to the turbine building floor during condensate reject).

Reactor Building Flashing

a. Inspection Scope

The team reviewed the circumstances surrounding the Unit 1 reactor building flashing that was dislodged during the steam release from the MSSVs (see Photograph 2). This review included identifying the reason the flashing was dislodged, evaluation of past similar events, and assessing the impact of the falling flashing to the Unit 1 transformers, and corrective actions taken by the licensee.

Photograph 2- Area where flashing was dislodged from Unit 1 containment

.4 Evaluation of Operating Experience did not address potential for dislodged RB

flashing affecting off-site power supply

Introduction:

A finding of very low safety significance was identified by the inspectors for the inadequate evaluation of operating experience (OE). Specifically, review of an event at another plant where building material was dislodged during a steam release and caused a loss of off-site power concluded that event was not applicable to Braidwood station. During the dual unit trip on August 16, 2010, reactor building flashing was dislodged during a steam release and was found on power lines and in the vicinity of the off-site power supplies. While there was no affect on the offsite power supply, the increased risk to them should have been fully evaluated and addressed as a result of the operating experience review.

Description:

On August 16, 2010, the unit 1 CW pumps 1A and 1C tripped and caused condenser vacuum to degrade. Operators initiated a turbine runback but vacuum continued to degrade until the turbine automatically tripped followed by reactor trip. The C-9 permissive, which would normally open the steam dump valves, was disabled due to failure of MCC 133V. Without the steam dump valves, the PORVs open to control temperature and pressure. In addition, two or three of the MSSVs open and subsequently close, with the exception of one which remains open. All of these valves release excess steam to the environment. The steam released from the combination of the PORVs and MSSVs caused portions of the containment flashing, located above the vent lines for these valves, to become detached and land on power lines and in the area of the off-site power transformer and equipment (See Photograph 3).

Photograph 3 - Flashing dislodged from Unit 1 containment located on main power transformer output lines On August 11, 1994, Braidwood Unit 1 experienced a spurious train A main steam isolation followed by an automatic reactor trip. Unit 1 PORVs and MSSVs lifted causing some flashing and a piece of the containment roof walkway to become dislodged piercing the turbine building roof. At the time, site engineering staff visually inspected the main steel framing and flashing for the containment walkway enclosure and determined that no structural damage had occurred. All sections of sheet metal siding blown off the walkway were accounted for and were placed in storage for future evaluation. The flashing and walkway were replaced.

On June 5, 2007, Braidwood station created AR637360, OPEX review potential vulnerability containment buttress siding, to review OE for an industry event that described a reactor scram in which the cross-under steam piping safety valves lifted; high steam flow was released from these valves; and caused portions of the turbine building metal siding to detach and contact bus bars on two of three reserve station transformers, which led to a loss of power to station buses. In the ARs condition description, the originator discussed the 1994 incident described above and also stated that the potential existed that the siding could have landed on the station auxiliary transformer (SAT) (preferred power source) for the emergency bus and cause a loss of off-site power (LOOP). It was recommended that engineering review the OE to determine if the buttress was susceptible to complicating emergency response (i.e.

LOOP) during a main steam line isolation from full power. This AR was closed based on initiating a corporate AR that will track the formal reviews of the OE.

On June 15, 2007, corporate AR637360 was initiated to track the formal reviews of the issues for Exelon sites. Braidwood assignment was captured in AR637360, assignments -01 and -02 with various sub-assignments. The corporate AR did not mention or seek to address the concerns or recommendations of the originator of the previous AR to evaluate the previous experience with the buttress siding being blown off and its potential effects on off-site power.

On September 18, 2007, sub-assignment 01/01 addressed the impact of the OE on the main steam reheater (MSR) system, and concluded that the Braidwood station design is different from the design of the plant discussed in the OE in that the MSR relief valve tail pipes are located adequately away from the building structure or the structure is concrete and that this configuration precludes the possibility of building structure dislodging during the relief valve lifting. The evaluation focused on the specific MSR configuration discussed in the OE and did not address main steam relief valves dislodging the buttress siding.

On September 18, 2007, sub-assignment 01/02 addressed OE with respect to the auxiliary power 480 VAC and above system/transformers, and concluded OE was not applicable to Braidwood station because the type of transformer inter-locks discussed in the OE were not used at the site. The evaluator mentioned that aluminum covers would likely protect the SATs and that debris from turbine building walls and other sources are unlikely to cause a lock-out. The evaluator did not address if debris could affect the SAT in other ways that may impact off-site power to the plant. However, the evaluator also went on to say that the primary feeds (345kv) are not protected. He noted two previous incidents where debris resulted in a lock-out of the SAT. In both events, the associated busses correctly transferred to the alternate supply or were re-energized by the emergency diesel generator (EDG). The evaluator concluded that this OE was not applicable to Braidwood station.

The Licensees Quality Assurance Topical Report (QATR) NO-AA-10, assigns major functional responsibilities. All personnel who support nuclear generation activities shall comply with the requirements of this document. As part of a three tiered approach to accomplish the oversight of safety, the document uses collection of program elements for implementing and/or reviewing areas of quality of plant operation and nuclear safety, which includes a review of operation experience.

Licensees Procedure LS-AA-115, Operating Experience Procedure, implements the Quality Assurance Topical Report requirement for this element.

The stated purpose of Procedure LS-AA-115 is to screen, evaluate, and act on current incoming OE documents and information to prevent or mitigate the consequences of similar events. It requires daily screening, classification, and evaluation of OE documents, and requires an evaluation documented in accordance with Attachment 1 of the procedure.

Procedure LS-AA-115, Attachment 1, OPEX Reviewers Guidelines, uses 27 questions to evaluate the OE. These questions were answered by the alternating current (AC)power and the main steam system engineer for their respective systems in separate sub-assignments as discussed above. However, the inspectors determined that the answers to the following questions were not adequate to meet the purpose of the procedure a. Question 2, is this OPEX document applicable to station SSCs? This question was answered no for the offsite power system. Answering this question no enables the evaluator to skip to question 25. The evaluation identified that debris had previously affected the operation of the SAT resulting in operation of the EDGs, an SSC. Since the initial AR was concerned with the reactor building flashing affecting loss of offsite power, and this evaluation concluded that offsite power could still be affected by debris, the answer should have been yes.

Further evaluations or actions should have been done to ensure the loss of offsite power was prevented, as discussed in the OE review, to meet the purpose of the procedure.

b. Question 10, are any other plant systems affected by this OPEX? This question was answered no for the main steam system. The evaluator stated that there were no other similar components impacted by this OPEX. It is also stated the main steam safety relief valves are also located adequately away from building structure or the structure is concrete so it would not be affected. The evaluator did not address the previous experience at Braidwood of the reactor building flashing falling off during a steam release identified in the original AR. This evaluation did not meet the purpose of the procedure to prevent or mitigate the consequences of similar events.

c. Question 12 b., did the event described in the in the OPEX include the failure of a nonsafety-related SCC resulting in actuation of a safety-related system? This was answered no for the main system even though the OPEX discussed how turbine building siding was blown off, impacted the off-site power equipment, resulted in the loss of off-site power and required the EDGs to start to supply AC power to safety related equipment. It is not known how the evaluator reached this invalid conclusion.

d. Question 24, will the information in this OPEX document require that a modification be implemented? This was answered no for the main steam system evaluation because the Braidwood MSR relief valves are appropriately located away from the building structure. Again, the evaluation did not address the reactor building flashing and its interaction with the MSSVs. Since the licensee did not address the susceptibility of the reactor building flashing becoming debris, but did conclude that the off-site power supplies were vulnerable to debris, this question was not answered appropriately to meet the purpose of the procedure to prevent or mitigate similar events.

Analysis:

The team determined that the licensees failure to adequately evaluate industry operating experience applicable to the reactor building flashing being dislodged during a steam release and its affects and risk related to off-site power supplies was contrary to Procedure LS-AA-115, Operating Experience Program and was a performance deficiency. The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of protection against external factors, and affected the cornerstone objective of limiting the likelihood of those events that challenge critical safety functions during shutdown. Specifically, not protecting the off-site power supplies from flashing falling from the reactor building which could result in a loss of off-site power would challenge the EDG to supply AC power during the plant shutdown.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, 0609.04, Phase 1 - Initial Screening and Characterization of findings, Table 4a for the Initiating Events Cornerstone. The inspectors answered "no" to the Initiating Events questions and screened the finding as having very low significance (Green).

The inspectors did not identify a cross-cutting aspect associated with this finding since it is not considered to reflect current performance.

Enforcement:

This finding does not involve enforcement action because no regulatory requirement violation was identified. Because this finding does not involve a violation and has very low safety significance, it is identified as a finding.

The licensee entered this issue into their CAP as condition report (CR) 01102706 and 01106404; inspected the flashing structures on both Unit 1 and Unit 2 reactor buildings; and installed temporary structural modifications to prevent the reactor building flashing from falling off during a future steam release until a permanent structural evaluation could be completed. (FIN 05000456/2010010-04, Evaluation of Operating Experience did not address potential for dislodged RB flashing affecting off-site power supply).

Dose Calculations for Release of Tritiated Steam

a. Inspection Scope

The team reviewed the licensees monitoring results for the August 16, 2010, steam discharge contaminated with tritium from the Unit 1 PORVs and unseated MSSV event.

The team assessed whether the licensees methods for quantifying the dose to the public from the contaminated steam discharge involved critical receptors.

The team reviewed whether the identified steam discharge occurrence was entered into 10 CFR 50.75

(g) records or will be reported on the 2010 Annual Radioactive Effluent Release Report or the Annual Radiological Effluent Release Report for the radiological effluent technical specifications.

The team assessed whether the licensee evaluated the steam condensate that spilled to the ground and reviewed whether there were remediation actions taken on the area.

The team assessed whether the tritium-contaminated discharge was monitored through the licensees groundwater protection initiative program.

For the unmonitored steam discharge, the team assessed whether an evaluation was performed to determine the type and amount of radioactive material that was discharged by:

(1) assessing whether sufficient radiological surveys/evaluations were performed to evaluate the extent of the contamination;

(2) assessing whether a survey/evaluation had been performed to include consideration of hard-to-detect radionuclides;

(3) determining whether the licensee completed offsite notifications, in accordance with the licensees Groundwater Protection Initiative implementing procedures; and

(4) assessing whether the licensee identified and addressed discrepancies through the licensees CAP Findings and Observations.

b. Findings and Observations

No findings were identified.

Following the Unit 1 trip on August 16, 2010, steam, containing tritium, was released to the atmosphere. The steam release occurred at 02:05 and ended on August 17, 2010, at 05:00 Central Time. There were approximately 312,500 gallons of steam discharged.

A portion of the saturated steam also condensed to water from the turbine building downspouts. The condensing steam was analyzed and found to contain 25,835 picocuries per liter (pCi/L) of tritium. The total tritium activity of the condensing steam on the ground inside the protected area was found to be less than approximately 1E-1 millicuries (mCi).

The team reviewed the licensees initial dose calculation to the public and noted that the licensee calculated a dose to a critical organ using a sampled tritium concentration data that was 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> post-steam discharge. This concentration may have been diluted by the make-up water from the condensate storage tank that contained a lesser concentration of tritium. In response to the teams observation, the licensee conservatively recalculated the dose to the public using a tritium concentration that was sampled and analyzed on August 9, 2010, 7 days prior to the event.

The licensee analyzed and calculated that the steam discharge in the environment contained approximately 43 mCi of tritium as a gaseous release. Specifically, the critical receptor dose (i.e., child critical organ) was 4.59E-6 mrem. The dose to the public due to gaseous effluents for both units was currently less than 1E-1 mrem.

Therefore, the additional dose impact to the public from the steam discharge was minimal (1E-1mrem + 4.56E-6 mrem= 1E-1 mrem), and was less than the regulatory limits.

The licensee had not completed files for the requirements of 10 CFR Part 50.75(g) at the time of the inspection. However, the licensee generated AR01102248 to the Radiation Protection Department to make the appropriate entry into the 10 CFR Part 50.75(g) files for information that the NRC considers important for decommissioning.

Additionally, the licensee will document the unplanned release on the licensees 2010 Annual Radioactive Effluent Release Report as required by the stations effluent monitoring program.

The condensation to the ground from the steam discharge will not be reported because the condensation did not leave the site as an effluent, but rather was recaptured. The licensee analyzed the concentration of tritium in the steam condensation to be 25,835 pCi/L.

The licensee will monitor the groundwater protection initiative monitoring wells at the site for any indication of tritium concentration anomalies as required by the stations groundwater monitoring program.

The licensee had not experienced primary to secondary leakage of the reactor coolant system (RCS) due to an SG tube rupture or a fuel failure in the recent past. Therefore, the only nuclide of significance was tritium because tritium leaches through stainless SG tubing and contaminates the secondary system. The licensee performs routine sampling at the secondary system for tritium on a weekly basis. The last chemistry surveillance was conducted on August 9, 2010. The tritium concentration on the Unit 1 secondary system was 3.64E-5 uCi/ml (36,400 pCi/L), with no indication of other radio-nuclides.

This activity was used to calculate the dose to the critical receptor (child critical organ).

The team reviewed that the licensees voluntary notification to the State of Illinois for the condensing steam that reached the ground. This voluntary notification was made by the licensee to the Local and State Government under Procedure LS-AA-1120, Reportable Event RAD 1.34, on August 16, 2010. No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

On September 30, 2010, the team presented the inspection results to Mr. A. Shahkarami and other members of the licensee staff at a public exit meeting held at Braidwood, IL (NRC presentation materials - ADAMS Accession Nos. ML102730329 and meeting summary ML102950118) and on November 12, 2010, with Mr. R. Gaston. The team confirmed that none of the potential report input discussed was considered proprietary.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements, which meets the criteria of Section 2.3 of the NRC Enforcement Policy for being dispositioned as an NCV.

The licensee violated TS Section 3.3.9, Boron Dilution Protection System, when they failed to enter the LCO Conditions A and C, which required 1-hour actions to close non-borated water source isolation valves and to verify that shutdown margins were within their limits. Unit 1 entered LCO 3.0.3 due to not completing the required actions.

Upon discovery, the licensee lowered the water volume in the volume control tank to clear the alarms and exit all the LCOs. This violation was not greater than green since the shutdown margin was verified within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and no significant change in reactivity occurred. The licensee entered this issue into the CAP as AR01101873 and has submitted LER 2010-002-00.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

A. Shakarami, Station Vice President

L. Coyle, Plant Manager

M. Marchionda-Palmer, Director, Site Operations

P. Simpson, Response Team Lead

D. Riedinger, Engineering

D. Stroh, Relief Valve Subject Matter Expert

W. Smith, Operations

M. Boyle, Maintenance

S. Butler, Operations

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

05000456/2010010-01; NCV Forebay inspect-and-clean activities did not ensure that

05000457/2010010-01 SSCs will be capable of performing their safety function (Section 4OA5.1)

05000456/2010010-02 NCV Failure to replace low margin fuses in MCC131X1 (Section 4OA5.2)

05000456/2010010-03; FIN Failure to identify and correct water discharged to the

05000457/2010010-03 turbine building floor during condensate reject (Section 4OA5.3)

05000456/2010010-04 FIN Evaluation of Operating Experience concerning Reactor Building Flashing (Section 4OA5.4)

Attachment 1