IR 05000259/2007008

IR 05000259-07-008, 05000260-07-008, 05000296-07-008; on 08/6-10, 08/20-24/2007; Browns Ferry Nuclear Plant, Units 1, 2 and 3; Biennial Baseline Inspection of the Problem Identification and Resolution Program

ML072830066
Person / Time
Site:	Browns Ferry
Issue date:	10/09/2007
From:	O'Connor S Reactor Projects Region 2 Branch 6
To:	Campbell W Tennessee Environmental Council
References
IR-07-008
Download: ML072830066 (29)

Text

ber 9, 2007

SUBJECT:

BROWNS FERRY NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT NOS. 05000259/2007008, 05000260/2007008 AND 05000296/2007008

Dear Mr. Campbell:

On August 24, 2007, the Nuclear Regulatory Commission (NRC) completed an inspection at your Browns Ferry Units 1, 2 and 3 reactor facilities. The enclosed inspection report documents the inspection results, which were discussed on August 24, 2007, with Mr. Gilbert Little and other members of your staff.

The inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel. This inspection was a routine biennial inspection of your Corrective Action Program for Units 1, 2, and 3 in the NRCs Baseline Inspection Program.

On the basis of the sample selected for review, the team concluded that, in general, problems were properly identified, evaluated, and resolved within the corrective action program.

However, based on the results of this inspection, the inspectors identified one finding of very low safety significance (Green). The finding was determined to involve violations of NRC requirements. However, because of the very low safety significance and because the problem has been entered into your corrective action program, the NRC is treating the finding as a non-cited violation (NCV), in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the NCV in this report, you should provide a response with the basis for your denial, within 30 days of the date of this report, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D. C. 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D. C. 20555-0001; and the NRC Resident Inspector at the Browns Ferry Power Station.

TVA 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Stephen C. OConnor, Acting Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos. 50-259, 50-260, 50-296 License Nos. DPR-33, DPR-52, DPR-68

Enclosure:

NRC Inspection Report 05000259/2007008, 05000260/2007008, 05000296/2007008 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-259, 50-260, 50-296 License Nos: DPR-33, DPR-52, DPR-68 Report No: 05000259/2007008, 05000260/2007008 and 05000296/2007008 Licensee: Tennessee Valley Authority (TVA)

Facility: Browns Ferry Nuclear Plant, Units 1, 2 & 3 Location: Corner of Shaw and Nuclear Plant Roads Athens, AL 35611 Dates: August 6-10 and August 20-24, 2007 Inspectors: K. Van Doorn, Senior Reactor Inspector(Team Leader)

R. Chou, Engineering Inspector C. Stancil, Resident Inspector, Browns Ferry M. King, Resident Inspector, Harris Plant Approved by: S. OConnor, Acting Chief Reactor Project Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000259/2007-008, 05000260/2007-008, 05000296/2007-008; 08/6-10, 08/20-24/2007;

Browns Ferry Nuclear Plant, Units 1, 2 and 3; Biennial baseline inspection of the problem identification and resolution program.

The inspection was conducted by a Senior Reactor Inspector, two Resident Inspectors and an Engineering Inspector. The inspection was a routine Reactor Oversight Process (ROP) biennial baseline inspection of the licensee Corrective Action Program (CAP) for Units 1, 2, and 3. One finding of very low safety significance (Green) was identified. 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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Identification and Resolution of Problems The licensee was effective in identifying problems at a low threshold and entering them into the CAP. Issues were typically properly characterized and evaluations such as root causes were sufficiently thorough and detailed. Strong management oversight of the CAP was evident.

Initial prioritization of issues and corrective actions appeared to be appropriate to risk and program guidance; however, numerous delays in completion of corrective actions had led to increased backlogs in closure of Problem Evaluation Reports (PERs). Recent management attention had resulted in the backlogs beginning to decrease at the time of this inspection. In addition, the inspectors concluded that the licensee had been slow to effect significant improvement in equipment reliability based on the number of equipment problems and timeliness of corrective actions. Also, some repeat problems, such as, adequacy of corrective action implementation were noted; however, these problems were improved from previous inspections.

The licensee was effective in evaluating internal and external industry operating experience items for applicability and taking appropriate action.

Based on review of the licensees Concerns Resolution Program (CRP), discussions conducted with plant employees from various departments, and review of many PERs, the inspectors did not identify any reluctance to report safety concerns. The inspectors concluded that licensee management routinely emphasized the need for all employees to identify and report problems using the appropriate methods established within the administrative programs.

A. Inspector-Identified and Self-Revealing Findings

Cornerstone: Barrier Integrity

• (Green) A green self-revealing non-cited violation (NCV) of Technical Specification (TS) 3.3.6.1 was identified for failing to recognize an inoperable Reactor Core Isolation Cooling (RCIC) steam flow isolation instrument resulting in exceeding the TS allowed outage time. The licensee entered the deficiency into their CAP for resolution.

This finding is greater than minor because it affected the ability of the licensee to ensure reactor containment isolation following a break in the RCIC turbine steam line and is associated with the Barrier Integrity cornerstone and the respective attribute of configuration control. The finding is of very low safety significance (Green) because it did not represent a degradation of the barrier function of the control room, did not represent an actual open pathway in the physical integrity of the reactor containment, or involve an actual reduction in defense-in-depth for the atmospheric pressure control or hydrogen control functions of the reactor containment. The finding directly involved the cross-cutting area of Human Performance under the correct labeling of components aspect of the Resources component; in that the licensee failed to ensure adequate work instructions and correct labeling were implemented. This directly contributed to the failure of craftsmen and quality control personnel to identify the improperly installed instruments H.2(c).

B. Licensee-Identified Findings None.

REPORT DETAILS

4OA2 Problem Identification and Resolution

a.. Assessment of the Corrective Action Program Effectiveness

(1) Inspection Scope The inspectors reviewed licensee Procedure SPP-3.1, Corrective Action Program, Revision 12, which describes the administrative process for the identification and resolution of problems, and its implementation. The inspectors evaluated the implementation of SPP-3.1 on Units 1, 2, and 3.

Procedure SPP-3.1 defines the licensees classifications of PER significance: A level was the most significant, typically safety-related and requiring a formal root cause analysis; B level was considered significant, required further evaluation, and may require a formal root cause determination based upon a management decision; C level was for routine problems warranting additional corrective evaluation and action; and D level was for issues that could be quickly resolved/closed and trended, or routine problems which were adequately addressed by immediate actions or the work control process. The licensees process also incorporates PERs designated as non-PERs to account for low level items which are, for example, duplicate to other issues identified in the CAP and therefore do not require followup.

The inspectors primarily reviewed PERs that had been initiated by the licensee since December 2005 (the period subsequent to the last NRC baseline problem identification and resolution inspection conducted in November 2005). The reviews mainly focused on issues associated with the following risk significant plant safety systems: Residual Heat Removal Service Water (RHRSW), RCIC, Core Spray Cooling (CSC), and the 250V DC Distribution system. In addition to the system reviews, the inspectors selected a representative number of PERs that were identified and assigned to the major plant departments which included Operations, Maintenance, Engineering, Chemistry, Radiation Protection, and Emergency Preparedness. The inspectors also reviewed a sample of the oldest PERs and oldest Work Orders (WOs) to determine if significant issues were backlogged. The inspectors also reviewed PERs associated with Licensee Event Reports (LERs), NCVs, licensee audits, and licensee self-assessments and reviewed a sample of anonymous PERs.

Reviews were conducted to verify that problems were being properly identified, appropriately characterized, screened for adverse trends, entered into the CAP, and corrective action items were completed as described in the corrective action plan. The inspectors also verified that the licensee adequately determined the cause of the problems and adequately addressed operability, reportability, common cause, generic concerns, and extent of condition. For significant conditions adverse to quality, the review was also to verify that the licensee adequately addressed the root and contributing causes and appropriately identified corrective actions to prevent recurrence.

The inspectors also confirmed the adequacy of a sample of justifications for canceled PERs.

The inspectors reviewed the preventive maintenance (PM) backlog, PMs in the grace period, and deferred PMs. The inspectors also selected a sample of deferred and/or extended PMs to verify that critical components were not adversely affected.

The inspectors also reviewed System Health Reports and the Maintenance Rule (MR)database for the selected systems to verify that equipment deficiencies were being appropriately entered into the Corrective Action and MR programs. The inspectors conducted plant walkdowns of equipment associated with the selected systems to assess the material condition and to look for any deficiencies that had not been appropriately documented.

Documents reviewed to support the inspection are listed in the Attachment.

(2) Assessment The inspectors determined that the licensee was effective in identifying problems and entering them into the CAP. PERs normally provided complete and accurate characterization of the subject issues. The threshold for initiating PERs was very low and employees were encouraged by management to initiate PERs. Equipment performance issues, in general, were being identified at an appropriate level and entered into the CAP with some minor exceptions noted. Although several NRC-identified PERs were initiated during the inspection for material condition issues, plant tours confirmed that the licensee threshold for identifying material condition issues was typically low.

Generally, the licensee performed adequate evaluations that were technically accurate and of sufficient depth. Formal root cause and apparent cause evaluations were sufficiently thorough and detailed.

The inspectors determined that, overall, the licensee properly prioritized issues entered into the CAP in accordance with SPP-3.1. However, the inspectors concluded that the licensee had been slow to effect significant improvement in equipment reliability based on the following information:

(a.) The Residual Heat Removal Service Water Heat Exchanger (RHRSW HX) Outlet Valves have had longstanding problems:

• Wiring issues have persisted since 1996. Seven separate instances have been documented, the most recent being July 2007. Problems consisted of broken motor lugs and leads and symptomatic repairs were performed using terminal block Raychem splices.

• Documented mechanical problems included separate issues of valve disc separation, stem shear, cracked stem, and separated handwheel (from 2003 to 2007). Again, symptomatic repairs were performed using valve disc modifications such as orifices and flow skirts.

• Over the course of plant operations, Units 2 and 3 RHRSW HX Outlet Valves routinely experienced loud local flow noise and significant vibrations during throttled Shutdown Cooling operations.

• The licensee did not aggressively pursue the root cause:

< To date, comprehensive vibration data on all three unit RHRSW HX Outlet Valves has not been acquired. WO 06-722292-000 was written to acquire vibration data on all three units outlet valves (twelve in all).

Three of four valves on U2 were completed, then the WO was closed.

New individual WOs have been written to address vibrations on Units 1 and 3 valves. Unit 3 WOs were written following inspector questioning.

< The licensee had not initiated its valve replacement project until the sheared and cracked stem occurrences in 2007.

< To date, the valve replacement project has not been properly scoped in that the root cause of high vibrations have not been validated with objective data. Subjective observations (less noise and visual shaking)are being used as project basis. The licensee is proceeding with purchasing and replacement of Unit 2 Walworth and Unit 3 Anchor-Darling valves with presumably vibration-friendly Unit 1 Copes-Vulcan valves. The design will not be complete until approximately February 2008. The first two valves (3A and 3C) are scheduled for replacement following the Unit 3 2008 Spring refueling outage.

• RHRSW HX Outlet Valves were added to MR (a)(1) status on May 31, 2006.

Two other RHRSW components, HX floating heads and pump motors, were added in July and October 2005, respectively. RHRSW components make up one third of the MR (a)(1) active list.

• RHRSW/Emergency Equipment Cooling Water (EECW) System Health Report Card Overall Ratings have been RED since the last period in Fiscal Year (FY)2005, previously turning YELLOW in the second period of FY2005, and turning WHITE in the first period of FY2005. Various system components contributed to the poor system availability and reliability: pump motor failures, piping through-wall leaks, keep-fill check valves, EECW strainers, RHRSW HX outlet valves, and pump performance issues.

• The Plant Health Committee approved the valve replacement project July 18, 2007, and added the RHRSW HX Outlet Valves to the Site Equipment Reliability Top Issues Matrix on August 7, 2007.

• The Change Control Board (site group for project approval and budgeting)approved and budgeted the RHRSW HX Outlet Valve replacement project in its last meeting, July 24, 2007.

(b.) The RHRSW Heat Exchanger Inlet Check Valves are another example of longstanding equipment issues:

• Check valves are sticking full or partially open after flow cessation from RHRSW Pump runs for periodic surveillance and operating instruction chemistry runs.

Maintenance history indicates many past occurrences of these sticking check valves.

• In December 2006, maintenance workers identified seven of twelve check valves stuck open while punching scribe marks that would better assist operators in determining valve position (PER 116511). WOs were written to inspect shaft end play and repack with less packing rings to reduce friction. Only Unit 2 valves are complete. Additionally, weighted close-assist lever arms were added to all three unit inlet check valves except two on Unit 3 Loop 1 which are scheduled.

The last two surveillances on Unit 1 have been successful.

• During this inspection, NRC inspectors identified five Unit 3 check valves full or partially open (4 full and 1 partially). On two separate occasions, two check valves were found full open. These check valves had neither the lever arms installed in the close-assist position or the packing ring WOs completed. The lever arms appear to be partially successful, although one valve with the close-assist lever arm was found partially open.

• The Functional Evaluation (FE) operability determination for PER 116511 was reviewed by inspectors and found to be weak with regard to the closure function of the RHRSW HX Inlet Check Valves. The original FE basis focused on upstream piping protection and radiological releases. The licensee stated that neither was of primary concern due to not having to credit a second passive mechanical failure (in addition to the fuel boundary), and that the FE would be revised to re-state this basis. The revised FE was reviewed by inspectors and found acceptable.

• The licensee stated that the RHRSW HX Inlet Check Valves were an unnecessary component in the system given the existing pump discharge check valves that perform a duplicate reverse flow function. Additionally, he stated that the HX inlet check valves were installed during initial plant construction for an RHRSW design that was not implemented to make RHRSW system pressure higher than RHR. The licensee indicated that long range plans may completely remove check valve internals, but that achieving full closure following flow cessation is the equipment focus at present. Check valve problem resolution is necessary to allow licensee focus on higher priority equipment problems. The check valves are identified as problem components on the System Health Report Card and Site Equipment Reliability Matrix.

(c.) During the RHRSW system walkdown with the system engineer:

• The inspector identified major corrosion on three RHRSW suction columns in the Intake Pump Station. The corrosion was caused by continued wetting of a section of each suction column from adjacent screen wash pump packing leakage (three separate pumps). There was no means of protecting piping from potential packing leakage and the screen wash drains appeared to be blocked.

The licensee initiated PER 128858 and the system engineer stated the intent was to consider to nondestructive testing and evaluation of the piping. The licensee has a history of service water piping corrosion problems (one of the top plant issues).

• The inspector identified that an auxiliary operator did not understand scribed check valve positions in the field. These were the scribe marks on the check valve spindles to assist operators in position verification. In response, the licensee initiated PER 128867.

• The inspectors identified that other surveillance and operating procedures were not changed to incorporate check valve verifications following flow cessation. In response, the licensee initiated PER 128907.

(d.) The licensees equipment reliability program is slow in responding to equipment reliability issues. However, the program appears to be a viable process if appropriate management attention and funding are applied:

• Review of 0-TI-495, Browns Ferry Equipment Reliability Program, and discussions with the equipment reliability and projects managers determined that the licensees equipment reliability program is robust and broad enough to encompass most equipment reliability issues. However, the program will require some finite time to be effective since it is relatively new. The program has established objective criteria for system health reporting and identification of system issues which are then escalated through multiple organizations for concurrence and prioritization. The end result is development of resolution plans which may include project scoping and budgeting depending on complexity and expense.

• The Equipment Reliability Program has been in place for approximately 1 1/2 years, but the site has received only a year of benefit due to partial implementation during the Unit 2 refueling outage and Unit 1 restart. In particular, the licensee has disbanded the Plant Health Weekly and T-16 workweek WO review and prioritization meetings which provide feeder information into the program.

• The Site Equipment Reliability Matrix, a consolidation of plant equipment issues from System Health Report Cards, contained 413 risk significant and critical component issues. 12 components had been identified as the Top Issues, entailing more intense site focus and resources. The licensee stated that there were many items, of the 413 in the matrix, that had not been scoped and prioritized for resolution. This incompleteness of the matrix appeared to exacerbate equipment issue resolutions which could impact plant operation.

• Discussions with Site Projects personnel indicated that the scoping and budgeting of pre-identified equipment issues do not appear to be a problem.

The Change Control Board is effective in budgeting and prioritizing scoped projects presented from the Plant Health Committee and works appropriately with other site organizations. Inspectors reviewed BP-315, BFN Project Approval and Change Control, and determined that the procedure did not reflect some aspects of the equipment reliability program such as utilization of the Site Equipment Reliability Matrix. BP-315 is being rewritten to better define and incorporate current processes.

(e.) On Units 2 and 3 or common systems, 15 of 133 total systems in the Plant Health Program are currently System Health RED or YELLOW. As expected, there are none on Unit 1 as a result of reconditioning systems for restart. Across all three units, 54 systems are WHITE . Note that the RHRSW/EECW are common systems.

Additional inspector observations are as follows:

(a.) Operations Surveillance Procedures 1- ,2- ,3-SR-3.1.3.3, Control Rod Exercise for Partially Withdrawn Control Rods, have been performed multiple times with a procedure error in the Prerequisite sections. Implementation of the prerequisite would have administratively prevented an operator from performing the surveillance procedure.

These monthly surveillance tests have been performed since revisions dated October 24, 2006, for Unit 1 and July 06, 2004, for Units 2 and 3. PER 128453 was initiated by the licensee to document the procedure error. PER 128558 was initiated as a result of the NRC inspector questioning multiple performances of these surveillance tests by operators over such a long period without identifying the error. The inspectors identified cases of several other procedural errors:

• PER 124681 was written in May 2007 for NRC resident inspector identification of a procedure error in the same surveillance procedure that also would not allow performance of the test as written.

• Inadequate procedure reviews performed in addressing PER 124681 missed opportunities to identify an additional procedural error that again prevented performance of the surveillance procedure.

• The procedure for exercising control rods (weekly for full-out and monthly for partials), insertions and withdrawals of one notch provided incorrect direction.

Therefore, the operators focused on the correct action per Technical Specifications and not the incorrect written direction. The finding did not result in an unexpected plant transient or equipment damage, and if left uncorrected would not have contributed to either. Eventually, during subsequent test performances, the procedure errors were discovered by other operators and corrected.

(b.) An NRC resident inspector previously identified leaking conduit seals in the Intake Pump Station cable tunnel that were also incorrectly labeled Appendix R seals. The licensee had initiated PER 123957, April 26, 2007. The PER was closed by a WO to resolve the leak without addressing the mislabeling. PER 129153 was initiated to document identification of the labeling issue by the NRC during this inspection. This is a minor finding in that it is only a labeling issue.

(c.) Two corrective actions in PER 119490 were documented as allowing closure to requests for changes. Corrective Action 1 initiated NEDP-3-4, Drawing Category Change form. Corrective Action 19 initiated SPP-2.5-3, Vendor Manual Change form.

However, these corrective actions do not meet procedural requirements in that action type corrective action can not be closed by a simple request for change.

(d.) B level PER 85316, Battery Cell Voltage Low, resulted in a Corrective Action to Prevent Recurrence (CAPR) to develop and implement a battery monitoring, testing, spare part, and replacement strategy that reduces the stations vulnerability to degrading battery performance and improves the ability to respond prior to plant operation being adversely impacted.

The C&D Technologies Vendor Manual storage recommendations for Safety Related Batteries KCR-11 stated:

Charged and wet batteries should be placed in service before the date stamped on the shipping carton when stored at 77°F (25°C). If storage beyond this time is required or temperature is in excess of 77°F (25°C), monitor battery at monthly intervals.

Given the environmental conditions seen by the batteries in storage at Browns Ferry (40

- 104 F) and the current practice of monitoring the battery every 6 months, the vendor recommended maintenance is not being followed. An unknown degraded battery condition could exist with batteries in inventory reducing the available inventory to levels below the limits specified in the CAPR. The licensee initiated PER 129327 to investigate this issue.

These deficiency examples were not considered to represent significant violations of applicable requirements.

(3) Findings

Introduction:

A green self-revealing NCV of Technical Specification (TS) 3.3.6.1 was identified for failing to recognize an inoperable RCIC steam flow isolation instrument resulting in exceeding the TS allowed outage time.

Description:

While performing a surveillance procedure for the Unit 1 RCIC system on May 27, 2007, the main control room indication for one of the two RCIC steam flow instruments did not respond as expected and was being driven downscale. The main control room RCIC steam flow indication instrument is not required by TSs; however, it shares high and low pressure sensing line connections with a TS Instrument, RCIC Steam Line Flow - High, which provides a containment isolation signal to isolate steam flow to the RCIC turbine if a break occurs in the steam line. Only one of the two channels of main control room indication were needed to satisfy the surveillance procedure acceptance criteria, so the procedure was completed successfully. A WO was written to troubleshoot the problem, but a PER was not initiated. On August 7, 2007, while executing the WO to troubleshoot the main control room RCIC steam flow indication, maintenance personnel identified that the low pressure and high pressure sensing lines were reversed affecting both the main control room RCIC steam flow indication and the RCIC high steam flow TS instrument. The licensee evaluated the condition and declared the RCIC high steam flow instrument inoperable. Subsequent investigation revealed that the high pressure and low pressure sensing line isolation valves were labeled incorrectly during Unit 1 restart activities in June or July of 2006. As a result, the routing of the instrument tubing for the RCIC steam flow instruments was performed based on the incorrectly labeled valves. Therefore, a condition of undetected inoperability existed for a period of time in excess of the allowable limits specified by TS 3.3.6.1, Primary Containment Isolation Instruments, Table 3.3.6.1-1, Item 4a. The investigation also revealed a potential missed opportunity to identify the reversed instrument lines during the execution of a work order to fill and vent the sensing lines.

The WO contained comments regarding reversed instrument lines for the A channel of RCIC steam flow, but no record of resolution or extent of condition could be located.

The licensee entered this performance deficiency into its CAP for resolution.

Analysis:

The inspectors referred to MC 0612 and determined that the finding is greater than minor in that it affected the ability of the licensee to ensure reactor containment isolation following a break in the RCIC turbine steam line. The inspectors determined that the finding is associated with the Barrier Integrity cornerstone and the respective attribute of configuration control. The inspectors evaluated this finding using MC 0609 and determined that it was of very low safety significance (Green) because it did not represent a degradation of the barrier function of the control room, did not represent an actual open pathway in the physical integrity of the reactor containment, or involve an actual reduction in defense-in-depth for the atmospheric pressure control or hydrogen control functions of the reactor containment. The finding directly involved the cross-cutting area of Human Performance under the correct labeling of components aspect of the Resources component; in that the licensee failed to ensure adequate work instructions and correct labeling were implemented. This directly contributed to the failure of craftsmen and quality control personnel to identify the improperly installed instruments H.2(c).

Enforcement:

TS 3.3.6.1 requires that the RCIC high steam line flow instrument shall remain operable. Contrary to this, the B channel of the Unit 1 RCIC Steam Line Flow -

High instrumentation was inoperable since being installed incorrectly. Because this finding is of very low safety significance and because it was entered into the licensees CAP as PER 128556, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000259/2007008-01, Failure to Recognize an Inoperable RCIC Steam Flow Isolation Instrument.

b. Assessment of the Use of Operating Experience

(1) Inspection Scope The inspectors reviewed selected industry operating experience items, including NRC generic communications, to verify that they were appropriately evaluated for applicability and whether issues identified through these reviews were entered into the CAP.

Documents reviewed are listed in the Attachment.

(2) Assessment The licensee was effective in evaluating internal and external industry operating experience items for applicability and entering issues into the CAP. The team found that communication for internal operating experience between other TVA sites was appropriately included and appropriate followup was being performed. The site also contributed to operating experience databases to allow other utilities to benefit from Browns Ferry operating experience.

c. Assessment of the Self-Assessments and Audits

(1) Inspection Scope The inspectors reviewed licensee audits and self-assessments focused on the CAP process and individual departments to verify that these were performed at appropriate frequencies, assessments were thorough and objective, findings were entered into the CAP, key corrective actions were implemented, and to verify that these findings were consistent with the NRCs assessment of the licensees CAP.

The team attended the licensees Management Review Committee (MRC) meetings, an MRC subcommittee meeting, plan of the day meetings, and a Plant Equipment Health meeting to confirm adequate oversight of the CAP and equipment issues including classification and prioritization for PERs, oversight of cause evaluations, and adequacy of PER closures.

The inspectors reviewed Nuclear Safety Review Board (NSRB) meeting minutes for three meetings in 2006 to verify that identified problems and issues were entered into the licensees CAP and that NSRB management attention items (MAIs) and recommendations (RECs) were being adequately tracked and resolved.

The inspectors also performed a review of recent trend analyses, departmental trends, and CAP performance indicators and trends.

Documents reviewed are listed in the attachment.

(2) Assessment Audits and self-assessments were effective in identifying issues and entering them into the CAP. These audits and self-assessments appeared to be comprehensive, were self-critical and identified substantive issues, numerous lower level problems, and areas for improvement. However, several of these self-assessments and audits identified repeat issues from previous self-assessments and audits in which prior corrective actions had proven ineffective. Similar issues, although minor, were identified by the inspectors. However, improvement was noted in all areas identified. Overall, the ability to perform self critical CAP assessments and enter identified issues into the CAP, was clearly evident.

The Nuclear Assurance (NA) organization continued to fully met its biannual functional area audit responsibilities in conformance with the Nuclear Quality Assurance Plan (NQAP).

Site management was purposely active and involved in the CAP and focused appropriate attention on significant plant issues.

During the Unit 1 restart and operation of Units 2 and 3, the NSRB continued to be very proactive in its oversight role. The board appeared to be engaged with the site and was effective in resolving numerous MAIs and RECs associated with nuclear, radiological, and industrial safety. However, the licensee contends that very recent licensee changes in board personnel and philosophy will reflect a more hands off approach with plant management. Results of these changes will need to be inspected at a later date.

Reviews of the CAP and other performance indicators such as backlogs indicated that the licensee was actively utilizing this information to highlight where improvement was needed, to enhance the corrective action process, and affect improvement where needed. One action, considered by the inspectors to be an effective initiative, was to implement an MRC subcommittee to provide additional emphasis on general improvement in PER documentation, improvement in cause evaluations, and improvement in PER closures. Improvements were noted in these areas, in part, due to this committee oversight.

The inspectors noted that valuable recommendations sometimes resulted from the various self-assessment processes. However, these were not required to be tracked for closure or disposition in accordance with good industry practice. Subsequent to this observation, the inspectors noted that PER 98713 issued August, 2006, covered the same issue. As of August 24, 2007, the licensee had failed to take corrective action.

d.

Assessment of Safety-Conscious Work Environment

(1) Inspection Scope Through technical discussions with members of the plant staff the inspectors developed a general perspective of the safety-conscious work environment at the site. The discussions also helped the inspectors determine if any conditions existed that would cause employees to be reluctant to raise safety concerns. The inspectors also reviewed the licensees CRP which provided an alternate method to the CAP for employees to raise concerns and remain anonymous. The inspectors interviewed the CRP Coordinator and reviewed a select number of completed CRP reports to verify that concerns were being properly reviewed and identified deficiencies were being resolved.

(2) Assessment Based on review of the licensees CRP, discussions conducted with plant employees from various departments, and review of many PERs, the inspectors did not identify any reluctance to report safety concerns. The inspectors concluded that licensee management routinely emphasized the need for all employees to identify and report problems using the appropriate methods established within the administrative programs.

All of the predominant methods established by the licensee, including the CAP, the WO system, and the CRP were readily accessible to all employees.

4OA6 Management Meetings

The inspectors presented the inspection results to Mr. Gilbert Little and other members of licensee management at the conclusion of the inspection on August 24, 2007. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

S. Armstrong, Performance Improvement

S. Berry, Systems Engineering Manager

C. Boschetti, Lead Electrical Engineer

T. Brumfield, Site Nuclear Assurance Manager

P. Chadwell, Operations Superintendent

J. Corey, Radiation Protection Manager

J. Davenport, Licensing

R. Davenport, Work Control and Planning Manager

J. DeDimenico, Asst. Nuclear Plant Manager

R. DeLong, Site Engineering Manager

A. Elms, Operations Manager

J. Emens. Licensing Supervisor

A. Fletcher, Field Maintenance Superintendent

J. Kennedy, Concerns Resolution Supervisor

R. Jones, General Manager of Site Operations

D. Langley, Site Licensing Manager

G. Little, Asst. Nuclear Plant Manager

J. Underwood, Acting Chemistry Manager

J. Woodward, Equipment Reliability Manager

NRC personnel

T. Liu, Acting Branch Chief, Division of Reactor Projects, RII

LIST OF ITEMS

Opened and Closed

05000259/2007008-001 NCV Failure to Recognize an Inoperable RCIC Steam Flow Isolation Instrument (Section 4OA2.a(3)).

Discussed

None.