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 C Reactor Projects Region 2 Branch 6
To:	Campbell W R Tennessee Environmental Council
References
IR-07-008
Download: ML072830066 (29)

Text

October 9, 2007

Tennessee Valley AuthorityATTN:Mr. William R. CampbellChief Nuclear Officer and Senior Vice President6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT: BROWNS FERRY NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION ANDRESOLUTION 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 atyour 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 tothe identification and resolution of problems, compliance with the Commission's 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 NRC's Baseline Inspection Program. On the basis of the sample selected for review, the team concluded that, in general, problemswere 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 NRC's Enforcement Policy. If you contest the NCV in this report, you should provide a response with the basis for yourdenial, 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 StatesNuclear Regulatory Commission, Washington, D. C. 20555-0001; and the NRC Resident Inspector at the Browns Ferry Power Station.

TVA2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's 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. O'Connor, Acting Chief Reactor Projects Branch 6 Division of Reactor ProjectsDocket Nos. 50-259, 50-260, 50-296License Nos. DPR-33, DPR-52, DPR-68

Enclosure:

NRC Inspection Report 05000259/2007008, 05000260/2007008,05000296/2007008

w/Attachment:

Supplemental Informationcc w/encl: (See page 3)

_________________________OFFICERII:CIPRII:DRSRII:DRPRII:DRPSIGNATURE/By E-Mail//By E-Mail//By E-Mail//By E-Mail/NAMEKVanDoornRChouCStancilMKingDATE10/ /200710/ /200710/ /200710/ /200710/ /200710/ /200710/ /2007 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO TVA3cc w/encl:Ashok S. Bhatnagar Senior Vice President Nuclear Generation Development and Construction Tennessee Valley Authority Electronic Mail DistributionJames R. DouetVice President Nuclear Support Tennessee Valley Authority 3R Lookout Place 1101 Market Street Chattanooga, TN 37402-2801H. Rick Rogers Vice President Nuclear Engineering &

Technical Services Tennessee Valley Authority Electronic Mail DistributionBrian J. O'GradySite Vice President Browns Ferry Nuclear Plant Tennessee Valley Authority Electronic Mail DistributionGeneral CounselTennessee Valley Authority Electronic Mail DistributionRobert G. Jones, General ManagerBrowns Ferry Site Operations Browns Ferry Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Decatur, AL 35609Beth A. Wetzel, ManagerCorporate Nuclear Licensing and Industry Affairs Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801D. T. Langley, ManagerLicensing and Industry Affairs Browns Ferry Nuclear Plant Tennessee Valley Authority Electronic Mail DistributionLarry E. Nicholson, General ManagerLicensing and Industry Affairs Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801John C. Fornicola, General ManagerNuclear Assurance Tennessee Valley Authority Electronic Mail DistributionRobert H. Bryan, Jr., General ManagerLicensing & Industry Affairs Tennessee Valley Authority Electronic Mail DistributionState Health OfficerAlabama Dept. of Public Health RSA Tower - Administration Suite 1552 P. O. Box 303017 Montgomery, AL 36130-3017ChairmanLimestone County Commission 310 West Washington Street Athens, AL 35611 TVA4Distribution w/encl

E. Brown, NRR L. Raghavan, NRR C. Evans (Part 72 Only)

L. Slack, RII EICS L. Mellen, RII OE Mail (email address if applicable)

RIDSNRRDIRS PUBLIC EnclosureU.S. NUCLEAR REGULATORY COMMISSIONREGION II Docket Nos:50-259, 50-260, 50-296License Nos:DPR-33, DPR-52, DPR-68 Report No:05000259/2007008, 05000260/2007008 and05000296/2007008Licensee:Tennessee Valley Authority (TVA)Facility:Browns Ferry Nuclear Plant, Units 1, 2 & 3 Location:Corner of Shaw and Nuclear Plant RoadsAthens, AL 35611Dates: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 PlantApproved by:S. O'Connor, Acting ChiefReactor Project Branch 6 Division of Reactor Projects

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 problemidentification 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 ProblemsThe licensee was effective in identifying problems at a low threshold and entering them into theCAP. 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 experienceitems for applicability and taking appropriate action. Based on review of the licensee's Concerns Resolution Program (CRP), discussions conductedwith 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 TechnicalSpecification (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 toensure 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

4.OTHER ACTIVITIES (OA)4OA2Problem Identification and Resolution a..Assessment of the Corrective Action Program Effectiveness (1)Inspection ScopeThe 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 licensee's classifications of PER significance: "A" levelwas 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 licensee's 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 sinceDecember 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.

5The inspectors also confirmed the adequacy of a sample of justifications for canceled PERs.The inspectors reviewed the preventive maintenance (PM) backlog, PMs in the graceperiod, 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)AssessmentThe inspectors determined that the licensee was effective in identifying problems andentering 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 accurateand 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 enteredinto 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) OutletValves have had longstanding problems:*Wiring issues have persisted since 1996. Seven separate instances have beendocumented, 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 discseparation, 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.

6*Over the course of plant operations, Units 2 and 3 RHRSW HX Outlet Valvesroutinely 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 HXOutlet 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 thesheared and cracked stem occurrences in 2007.To date, the valve replacement project has not been properly scoped inthat 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 ReportCard 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 oflongstanding equipment issues:

7*Check valves are sticking full or partially open after flow cessation from RHRSWPump 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 valvesstuck 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 orpartially 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 wasreviewed 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 anunnecessary 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 theIntake 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 8was to consider to nondestructive testing and evaluation of the piping. Thelicensee 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 scribedcheck 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 werenot changed to incorporate check valve verifications following flow cessation. In response, the licensee initiated PER 128907.(d.) The licensee's equipment reliability program is slow in responding to equipmentreliability 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," anddiscussions with the equipment reliability and projects managers determined that the licensee's 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 issuesfrom 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 andbudgeting 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 9some aspects of the equipment reliability program such as utilization of the SiteEquipment 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 HealthProgram 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 forPartially 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 ofa 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 missedopportunities 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 forpartials), 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 IntakePump Station cable tunnel that were also incorrectly labeled Appendix R seals. Thelicensee 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 aminor finding in that it is only a labeling issue. (c.) Two corrective actions in PER 119490 were documented as allowing closure torequests for changes. Corrective Action 1 initiated NEDP-3-4," Drawing Category 10Change" 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 todegrading 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 RelatedBatteries 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 ofapplicable requirements.

(3)FindingsIntroduction: A green self-revealing NCV of Technical Specification (TS) 3.3.6.1 wasidentified 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 onMay 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 TS's; 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 steamflow 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 11investigation revealed that the high pressure and low pressure sensing line isolationvalves 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 greaterthan 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 shallremain 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 licensee's 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 ScopeThe inspectors reviewed selected industry operating experience items, including NRCgeneric 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) AssessmentThe licensee was effective in evaluating internal and external industry operatingexperience 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 ScopeThe inspectors reviewed licensee audits and self-assessments focused on the CAPprocess 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 NRC's assessment of the licensee's CAP. The team attended the licensee's Management Review Committee (MRC) meetings, anMRC 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 forthree meetings in 2006 to verify that identified problems and issues were entered into the licensee's 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)AssessmentAudits and self-assessments were effective in identifying issues and entering them intothe 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.

13The Nuclear Assurance (NA) organization continued to fully met its biannual functionalarea audit responsibilities in conformance with the Nuclear Quality Assurance Plan (NQAP).

Site management was purposely active and involved in the CAP and focusedappropriate attention on significant plant issues. During the Unit 1 restart and operation of Units 2 and 3, the NSRB continued to be veryproactive 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 plantmanagement. 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 thevarious 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 ScopeThrough technical discussions with members of the plant staff the inspectors developeda 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 licensee's 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)AssessmentBased on review of the licensee's CRP, discussions conducted with plant employeesfrom 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 14problems 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. 4OA6Management Meetings The inspectors presented the inspection results to Mr. Gilbert Little and other membersof 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, CLOSED AND DISCUSSED

Opened and Closed

05000259/2007008-001NCVFailure to Recognize an Inoperable RCIC SteamFlow Isolation Instrument (Section 4OA2.a(3)).

Discussed

None.

2Attachment

LIST OF DOCUMENTS REVIEWED

ProceduresConcerns Resolution Staff Instruction 1, CRS Administration, Rev. 9NEDP-12, System, component and Program Health, Equipment Failure Trending, Rev. 8

0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting -

10CFR50.65, Rev. 0028

SPP-1.6, TVAN Self Assessment Program, Rev. 13

SPP-1.7, Excellence In Performance Program, Rev. 4

SPP-3.1, Corrective Action Program, Rev. 12

TVA-NQA-PLN89A, Nuclear Quality Assurance Plan

0-TI-495, Browns Ferry Equipment Reliability Program, Revision 4

BP-315, BFN Project Approval and Change Control, Revision 3A

2-OI-47, Turbine Generator System

1-SR-3.3.6.1.5(4A/A), Core Isolation Cooling Systems RCIC Turbine Steam Line High Flow Instrument Channel A Calibration

1-SR-3.5.3.3(COMP), RCIC Comprehensive Pump Test

MCI-0-000-BFV001, Generic Maintenance Instructions for Butterfly Valves

MCI-1-064-BFV002, Containment Ventilation System Butterfly Valves Disassembly, Inspection, Rework, and ReassemblyProblem Evaluation ReportsRHRSW system PERs81236, Unit 2 2A RHRSW HX Leakage87900, RHRSW 2B/2D Piping Pinhole Leaks in Pipe Tunnel

88881, EECW Pump D3 Pump Motor Failure Due to Ground Fault

90591, RHRSW/EECW Pump Motors Moving into MR (a)(1)

90674, RHRSW Pump C1 Rated Flow Failure

267, Unit 2 2A RHRSW HX Outlet Valve Failed to Open Due to STA Switch

91780, Unit 3 Reactor Scram resulting from Deficient Switching Order

99498, Unit 3 RHRSW HX Outlet Valve Motor Leads Broke

104410, RHRSW Pump C1 Impeller Adjustment - Stainless Steel versus Bronze

104621, RHRSW HX Outlet Valve Failures Due to Vibration

106779, RHRSW Pump Flow Surveillance Failures - 13 in 12 Months

106844, RHRSW Pump A2 Lower Motor Bearing High Vibration

108801, RHRSW Pump A2 Inadequate Corrective Action for PER 106844

109971, RHRSW Pump A2 Exceeded Maintenance Rule Performance Criteria

111067, RHRSW A1/A2 Pumps Cross-Tie Valve Hard to Operate

2834, RHRSW Pump C2 Motor Cable Damaged During Work

114574, RHRSW A1/A2 Pumps Cross-Tie Valve

116511, Seven of Twelve RHRSW HX Inlet Check Valves Stuck Open

119490, Unit 3 Scram from Demineralizer PLC in Manual

119767, RHRSW Pump B1 Cable Termination Damage

3Attachment119773, RHRSW Pump A2 Underground Cable Failure Due to Water-Treeing119954, Inadequate Sump Pump Design Caused RHRSW Pump A2 Cable to Fail

20891, Unit 2 RHRSW HX Outlet Valve Failure to Stroke in Normal Time Band

2218, Unit 2 2D RHRSW HX Valve Disk/Stem Separation

26762, RHRSW HX Inlet Check Valves Continue to Stick Open - Test Criteria

26885, RHRSW HX Inlet Check Valves Stuck Open Following Chemical Addition

27137, Unit 3 RHRSW 3A HX Outlet Valve Failed to Close or OpenRCIC system PERs106204, Unidentified EPU Impact on HPCI/RCIC Initiation108947, 360 Degree Linear Indication at Toe of Weld

2206, MSPI Baseline Data Errors

116947, EQ Issue - Unqualified Contact Blocks Installed on Hand Switch 1-HS-71-17B

118029, Add Drain Fittings for RCIC and HPCI Boiler Steam Lines

118093, Field Wires Incorrectly Labeled

118336, LOOPS 1-L-3-208A and 1-L-3-208C Calibration Values

28547, Inoperable RCIC Flow Instrument

28556, Unit 1 RCIC Steam Flow Instruments Configuration Discrepancy

28848, Compliance Loop 1-F-71-1B Indication Driving Downscale

24928, RCIC Steam Flow Indicators in MCR do not Indicate 0 lbm/hr with System in Standby

25350, RCIC Servo Removal and InstallationCSC system PERs88274, Senseline Program Self Assessment

BFR-REN-05-007 Finding Related to Code List91688, Core Spray Pump 2A Had the Excess Vibration Test Readings

93083, Core Spray Sparger 3-PDIS-075-0028 Switch Function was Found outside the Allowable Values

95706, M&TE Pressure Gauge E21967 Was Out of Tolerance In the Post Check

99373, A Search Unit for Nozzle to Vessel Weld Exams Was Found not Qualified to the

EPRI/PDI Procedure

PDI-UT-6, Rev. F

119221, Unit 2 Tech Spec 3.0.3 Entry During Unit 3 CASA Logic Surveillance Test

105189, Non Conservative NPSH Calculation for the Core Spray Pump Flow

108425, B3 EECW Pump Breaker Tripped When the 27SCX and 27 SCY Relays Were Manually Operated

114422, Relay 0-RLY-211-CASA-1 Failed to Energize

95905, Hancock Check Valve Replacement Parts Did Not Meet TVA Spec 9463 and ASME

Section XI Requirements

68160, RHR Check Valves Keep Fill Failed on LLRT test

250V DC system PERs

2651, Shutdown Board Battery A Cell 39 Voltage

116792, Critical Component Failure PER - Main Bank 1 Battery Charger 85316, Battery Cell Voltage Low88513, 1 Hour Limit Exceeded After Battery Cell Reading Found Low

4Attachment88844, Shutdown Board Battery A Cell Parameters Cause Unplanned LCO Entry89260, Shutdown Board Battery A Cell Voltage Low

89587, Unplanned LCO

SB-A Battery

89729, 250 Volt Main Bank

89936, Unplanned Entry into LCO

91140, Unplanned LCO Entry due to

SB-A Inoperability

93531, 3-SR-3.8.4.1(DG)

204, Discrepancies for Modifications Resolution

206, Discrepancies for Engineering Resolution

248, Battery Procedure Errors

103902, Inadequate Performance of 3-SR-3.8.4.1(DG)

107565, SR EnhancementOther PERs87178, 2C RFP Trip88211,

SEN-254 Operating Procedure Review

91454, Insufficient Knowledge of BFN VFD's

2719 Unit 3 Operators Did Not Refer to ARP for RBM Alarms While Pulling Rods

93694, House Keeping Deficiencies

94427,

TS-71-2P Out of Tech Spec Value

94672, PM Deferral for Condensate Storage Tank Inspection

101460, PER Extension Process Problem

101585, Diesel Generator Water Leak

101867, Weaknesses in Management Oversight of CAP

111670, Five-Year Self-Assessment Plan not Maintained

2893, Apparent Cause Evaluations Need Improvement

2894, Root Cause Analysis Need Improvement

2895, Improvement Needed in Effectiveness Reviews

2896, Ineffective use of Integrated Trend Process

113089, System 573 SPOC II SID Coding and Turnover Boundary Issues

114972, Upper Tier Requirements Not in Design Process

115699, Cable Routing Issue

115833, Inadequate Unit 1 RHR Logic Test Instruction

115837, Inadequate Unit 1 Test Instruction Causes Unit 2 ECCS Unplanned LCO

116361, SER 6-08 Reactor Operation in an Unanalyzed Region

117916, U2 Reactor Scram

117921, Electrical Cable Separation

21393, Radcon Technician Reporting of PCEs

21604, Rad Con C-Zones

2731, 161 Capacitor Banks

2933, Review NRC Information Notice 2007-09: Equipment Operability Under Degraded Voltage

23456, Coolant Level

23957, Intake Pump Station Cable Tunnel Water Leakage onto B1 Pump Cable

24017, PER Coordinator

24092,

BP-336 Attachment A not Included with 0-SI-65-9-B Data Package

5Attachment125408, Unit 1 LPRM Gains not Properly Set125410, Continuous use Procedure

25738, NA Organization

25834, NSRB Oversight

26237, Questions Regarding Support of the Audit Program

26933, GE Safety Communication 07-08, Inadvertent CRD Rod Withdrawal

26875, Late Cause Determination EvaluationsPERs Associated with DepartmentsChemistry Department

94694, Weaknesses in the Data Trend Review Program96373, Chemistry Management Expectations for Conducting Observations not Met

100521, Current Lab Resources Impacting the Chemistry Labs Ability to Meet Weekly and Monthly Frequencies

101672, Chemistry Potential Increasing Trend in Human Performance Events

2133, Potential Discrepancies and/or Enhancements Noted with Sampling Procedures

107086, Significant Increase in Quality Deficiency Investigations

109419, Potential Human Performance Issue not Addressed

114806, Human Performance Event Increase

117579, Inadvertent Transfer of 70,000 Gallons of Elevated post-UV Anion Water

23101, Corrective Actions did not Appear to Completely Address Stated Actions

23102, Corrective Action did not Appear to Address Stated Action

2190, Control Bay Chiller Out of Limits for all ParametersEngineering Department

81634,

SEN-254 Repeat Recirculation Pump Downshift & Lack of Timely Response83123, Design Basis for RHR HX Leakage Note: Most of the equipment related PERs and some of the miscellaneous PERs were Engineering Department assigned PERsRadiation Protection Department

89455, Procedural Guidance Deficiencies96543, Source Leakage Lead to Unplanned LCO

96570, Posting Violation

247, Number of People in Drywell Excessive

99898, Potential Trends in Activity Found During Incoming Counts Clothing and Personal Items

100375, Potential Trend with Activity on Individuals Checking In

2788, Improvement Needed for Focus Areas and Performance Improvement Areas

106169, Possible Overweight Lead Blankets

106314, Negative Trend in Radiological Work Practices

106829, 70 Unexpected Dose Rate Alarms

6AttachmentMaintenance Department95869, Review on SQN

PER 94144 for a Clearance Requirement06678, Problems on PER Supervisory Review

291, A Diesel Generator Automatically Started

96604, Diver Hand Injury During the Performing Maintenance of the Intake Tunnel Drain Valve

109448, The 2A CRD Pump Rotating Element Purchased Did Not Meet Design Criteria

110479, Loss of Unit 2 & 3 Fire Pump Start

2670, Incorrect Material Used on the 2A & 2B Reactor Recirculation Pump

116524, Components Failed Due to the Preventive Maintenance Not Implemented Per Schedule

101868, The Division Separation Required for Cables and Internal Wiring Associated with DCN

51090 was inadequate

110926, A Breach on the Secondary Containment Without Permit

103343, Unit 1 LPCI MG Set Tech Spec Submittal

TS-427 Was inadequateOperations Department

96895, Annunciators Disabled without 50.59 Review97146, Significant Audit Issue

83613, Focus Area: Operator Fundamentals

101180, Ineffectiveness of Reactivity Management Review Board

109118, Group 1 Isolation

118024, Oil Sheen in Hot Water Channel

119305, Unit 2 Increased Core Flow

2211, Difference Between OI Values and Values on Hand Held PC

2283, Leak Into Unit 1 Torus

25637, Operations Interface with Work ControlIndustry Operating Experience ReportsNER No. 05-0659; Review of Crane, Hoisting, Lifting, and Rigging Related EventsNER No. 05-1406,

IN 2005-19, Effect of Plant Configuration Changes on the Emergency Plan

NER No. 05-1410, NRC Information Notice 2005-23: Vibration-Induced Degradation of Butterfly Valves

NER No. 05-1424,

NSAL-02-14 R2, Steam Line Break During Mode 3 for Westinghouse NSSS

Plants

NER No. 05-1551, NRC

IN 2006-21 OE Regarding Entrainment of Air Into Emergency Core Cooling and Containment Spray System

NER No. 06-1590, Degradation of Essential Service Water (ESW) Piping

NER No. 07-0871, Intake Structure Blockage Vulnerabilities

NER No. 06-1435, Westinghouse

TB-06-15, Unqualified Service Level 1 Coatings on Equipment in Containment

NER No. 06-0099,

IN 2006-01 - Torus Cracking in a BWR Mark I Containment

NER No. 07-0863, Flowserve 10

CFR 21 Report Regarding Borg Warner 3" and 4" Swing Check Valves

7AttachmentNER No. 06-0481,

IN 2006-09, Performance of

NRC-Licensed Individuals While on Duty with

Respect to Control Room Attentiveness

NER No. 06-1084,

IN 2006-14 & Supplement 1, Potential Defective External Lead Wire Connections in Barton Pressure Transmitters

NER No. 06-1929,

IN 2006-29, Potential Common Cause Failure on MOVs due to Stem Nut Wear

NER 07-0244

IN 2007-6 Potential Common Cause Vulnerabilities in Essential Service Water

(ESW) Systems

NER 06-1590 SER 7-06 Degradation of Essential Service Water Piping

NER 06-1819, Reactor Operation in an Unanalyzed Region

NER NO: 05-1263, Weaknesses in Operator Fundamentals

NER NO: 05-1410, NRC

IN 2005-23: Vibration-Induced Degradation of Butterfly Valves

NER NO: 06-1512,

IN 2006-22: Ultra-Low-Sulfur Diesel Fuel

NER NO: 07-0508, NRC

IN 2007-09: Equipment Operability Under Degraded Voltage ConditionsOther DocumentsMRC Subcommittee guidance and checklist dated 09/20/2006Multiple PM Deferrals curve for May, 2006 to August, 2007

Site Equipment Reliability Top 10 Matrix Site Equipment Reliability Top Issues Matrix Anonymous PER list December 16, 2006 to July 2, 2007

Non-PER list for December 16, 2006 to July 2, 2007

Oldest PER list Oldest Work Order list

Procedure

Change Request 05-2931,-2,-4, and -7 for

OI-92 and ARP-9-5A

Alarm Response Procedures 1-,2-,3-ARP-9-5A, Panel 9-5, 1-XA-55-5A

Engineering Design Change 65437 Testing Requirements for RHR Hxs Preventive Maintenance

500163737 Unit 3 RHR HX Leakage Sampling Work Order (WO) 07-712162-000 Unit 3 RHR HX Leakage Sampling

WO 04-711093-006, Flush and backfill instrument sensing lines on pnl 25-7A

WO 06-719088-040, Install pipe plugs in used port of transmitters 1-PDT-071-0001A and 1-

PDT-071-0001B.

WO generated due to PER 108449.

WO 06-725158-012, perform procedure 1-SR-3.3.6.1.5 (4A/A) per step text of this work order

WO 06-725237-003, replace starter that is binding in charger

WO 06-726048-000, Facilities to perform June monthly battery check and charge

WO 06-726049-000, Facilities to perform July monthly battery check and charge

WO 07-710678-000, Residual oil in CT#3 Pump B and has leaked into the hot water channel

WO 07-718184-000, RCIC steam flow

WO 07-719322-000, Facilities to perform August monthly battery check and charge Justification of Deferral of 91-18 Actions, U3C12 Refueling Outage, March 16,2006

Functional Evaluation

PER 87900 RHRSW Pipe Degradation on 2B/2D Supply, October 7,2005

U0-SYS 023/067 RHRSW/EECW System Health Report Card, FY2007-P1

BFN Maintenance Rule (a)(1) SSCs, July 18,2007

Cause Determination Evaluation (CDE) 2005-08-10, A and C Room Sump Pump MR Functional Failures

8AttachmentCDE 2005-08-05, 2B/3B RHR Heat Exchangers Removed from Service Due to 2B/2D RHRSW

Piping Leaks Site Equipment Reliability Top Issues Matrix, July 17,2007

Core Spray System Health Report Cards fro FY2007 - P1, Unit 1

Core Spray System Health Report Cards fro FY2007 - P1, Unit 2

Core Spray System Health Report Cards fro FY2007 - P1, Unit 3Non-Cited Violation Corrective Action ReviewsNCV 50-260/2006002-02 (PER 85130 & 99193), Failure to Report a Safety System Functional

Failure per 10 CFR 50.73

NCV 50-260/2006002-01 (PER 98414), Failure to Perform PSA Risk Evaluation for Multiple Inoperable Components

NCV 50-296/2006003-02 (PER 100822), Maintenance Rule Performance Criteria Exceeded for System 064 Primary Containment

NCV 50-259/2006012-02 (PER

101868 & 102752), Measures were not Adequate to Assure that Cables for 480V MOV Boards 1A and 1B in Panel 1-9-23 Bay 8 were Separated

NCV 50-259/2006007-01 (PER 106420), Failure to Construct Instrument Tubing Sorrorts in Accordance with Design Drawings

NCV 50-259/2006009-04 (PER 113105), Motor T Drain on 1-MVOP-075-0009 was plugged with Paint

NCV 50-259/2006009-05 (PER 113169), O-Ring for RHR Service Water Component was not Replaced as Required During Performing the Maintenance

NCV 50-259X/2006009-02 (PER 115699), Measures Were Not Adequate to Assure that Cables from Opposite Divisions Were Separated

NCV 50-259/2006009-07 (PER117046), Inadequate Instructions for Maintenance on HCUs

NCV 50-259, 260, 296/2007002-03 (PER 81364), Failure to Properly Prepare a Radioactive Materials Package for Shipment

NCV 50-259/2007009-02 (PER 117921), Criteria Was not Adequately Defined to Ensure Divisional Separation for Cables Were Maintained

NCV 50-259/2007009-01 (PER 117977), Valve 1-SHV-002-0705 for 1B Core Spray Pump was Found in the Closed Position which is normally open valve.

NCV 50-260, 296/2007002-05 (PER 119016), Work Hours for I&C Mechanics Exceeded Overtime Limits Without Prior Authorization

NCV 50-260/2007002-06 (PER 119305), Operation of Unit 2 Outside of the Limits Allowed by Power-Flow Map

NCV 50-259, 260/2007002-02 (PER

119482 & 119829),Two Examples of Failure to Perform Adequate Surveys

NCV 50-259/2007003-03 (PER 125408), Non-Conservative APRM/LPRM Gain Settings Result in Neutron Flux Setdown Setpoint in Excess of TS LimitLicensee Event Report Corrective Action ReviewsLER 50-260/2005-007-00 (PER 87178 & 87198), Reactor Scram due to Low Reactor WaterLevel Caused by Loss of Feedwater Pumps

LER 50-296/2005-003-00 (PER 91811), Unit 3 Scram from Deficient Switching Order

9AttachmentLER 50-296/2006-002-00 (PER 109107), Unit 3 Scram from Loss of Both Recirculation PumpsLER 50-296/2006-003-00 (PER 109756), Manual Scram in Response to Main Turbine Electro-

Hydraulic Control System Fluid Leak

LER 50-259/2006-008-01 (PER 110926), Secondary Containment Breach

LER 50-260/2007-001-00 (PER 117916), Automatic Turbine Trip & Reactor Scram Due to Equipment Failure During Performance of the Main Generator Rheostat Test

LER 50-296/2007-001-00 (PER 119490), Unit 3 Scram from Low Reactor Water LevelDocuments Associated with Performance Evaluation, Self- Assessments, and AuditsAudit No. BFA0603 Browns Ferry Nuclear Plant Engineering Functional Area AuditAudit No.

BFA 0602, Maintenance Functional Area Audit Audit No. SSA0502, Radiological Protection and Control Audit Audit No. SSA0503, Quality Programs Audit Audit Report BFA0601, Operations Functional Area Self-Assessment (SA)

BFN-ENG-05-003, Maintenance Rule Program

SA

BFN-SIT-06-006, Self Assessment Program

SA

BFN-TRN-07-003, Maintenance and Technical Training Programs Comprehensive

Assessment

SA

NA-BF-07-003, Quality Assurance Program Effectiveness

SA

NA-BF-06-029, Root Cause Analysis Quality

SA

NA-BF-06-011, Corrective Action Program Extension Process

SA

BFN-M&M-06-003 Appendix F, Maintenance Rework

SA

BFN-M&M-06-001, Preventive Maintenance Program

SA

BFN-RP-07-001, As Low As Reasonably Achievable Program

SA

BFN-TRNOPS-06-SS04, Effectiveness Review of Corrective Actions to Support BFNPER

2461

SA

BFN-SIT-07-002, Corrective Action Self Assessment

SA

BFN-SIT-06-008, Corrective Action Program

SA

BFN-SIT-06-003, Review of Apparent Causes

SA

BFN-CEM-07-002, Chemistry Training for Performance Improvement

SA

BFN-CEM-07-SS02, Management of Chemistry Training Processes and Resources

SA

BFN-SIT-06-007, Effectiveness of Corrective Actions from Previous AFIs

SA

BFN-NA-07-SS05, Nuclear Assurance Integrated Trend Review for October, 2006 -

January, 2007

NA-BF-07-002, Nuclear Assurance Oversight Report for October 1, 2006 Through December 31, 2006

NA-BF-07-011, Nuclear Assurance Oversight Report for April 1, 2007 Through June 30, 2007

NA-BF-07-007, Nuclear Assurance Oversight Report for January 1, 2007 Through March 31, 2007

NA-BF-06-029, Nuclear Assurance Assessment of Root Cause Analysis Management Observation Report for 12/15/2005 to 07/09/2007

PER Backlog Trend for June 2006 through July 2007

MRC Acceptance Rate for June 2006 through July 2007

Self-Assessment Schedule for FY07-FY11

Site Annual SA Plan/Status for 3

rd Quarter 2006 through 2

nd Quarter 2007BFN Chemistry/Environmental Integrated Trend Review for July-September 2006

10AttachmentCorrective Action Program Quality Index through August 17, 2007Elective Maintenance Backlog Workoff Curves for 08/02/2007 to 08/31/2007

Integrated Site Analysis from October to December FY 2006

Integrated Site Analysis from July to September 2006

Integrated Trend Review for Third Quarter 2006

Nuclear Assurance Audit Schedule 2005-2007