IR 05000324/2007002

IR 05000325-07-002, 05000324-07-002; 01/01/07 - 03/31/07; Brunswick Steam Electric Plant, Units 1 and 2; Refueling and Other Outage Activities

ML071200283
Person / Time
Site:	Brunswick
Issue date:	04/30/2007
From:	Randy Musser NRC/RGN-II/DRP/RPB4
To:	Scarola J Carolina Power & Light Co
References
IR-07-002
Download: ML071200283 (44)

Text

April 30, 2007 Carolina Power and Light Company ATTN: Mr. James Scarola Vice President Brunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461 SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NO /2007002 AND 05000325/2007002, AND ANNUAL ASSESSMENT MEETING/REGULATORY PERFORMANCE MEETING

SUMMARY

Dear Mr. Scarola:

On March 31, 2007, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 19, 2007, with Mr. Waldrep and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, one self-revealing finding of very low safety significance (Green) was identified. The finding was determined to involve a violation of NRC requirements.

Additionally, four licensee-identified violations which were determined to be of very low safety significance are listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs), in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Brunswick Steam Electric Plant.

CP&L

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/

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos: DPR-71, DPR-62 Enclosure:

Inspection Report 05000325, 324/2007002 w/Attachment: Supplemental Information cc w/encl: (See page 3)

OFFICE RII:DRP RII:DRP RII:DRP RII:DRS RII:DRS RII:DRS RII:DRS SIGNATURE JDA for JDA KJK2 RCC2 RCT1 HJG1 AND NAME EDiPaolo:rcm JAustin KKorth RChou RTaylor HGepford ANielsen DATE 04/26/2007 04/26 /2007 04/26/2007 04/26/2007 04/27/2007 04/27/2007 04/26/2007 E-MAIL COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE RIII:DRS RII:DRS SIGNATURE GBK1 JXD2 NAME GKuzo JDiaz Velez DATE 04/26/2007 04/26/2007 4/ /2007 4/ /2007 4/ /2007 4/ /2007 4/ /2007 E-MAIL COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO

CP&L cc w/encl:

Benjamin C. Waldrep, Director Site Operations Brunswick Steam Electric Plant Carolina Power & Light Company Electronic Mail Distribution James W. Holt, Manager Performance Evaluation and Regulatory Affairs PEB 7 Carolina Power & Light Company Electronic Mail Distribution Terry Hobbs, Plant Manager Brunswick Steam Electric Plant Carolina Power & Light Company P. O. Box 10429 Southport, NC 28461 Paul Fulford, Manager Performance Evaluation and Regulatory Affairs PEB 5 Carolina Power & Light Company P. O. Box 1551 Raleigh, NC 27602-1551 Edward T. O'Neil, Manager Training Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail Distribution Randy C. Ivey, Manager Support Services Carolina Power & Light Company Brunswick Steam Electric Plant Electric Mail Distribution Garry D. Miller, Manager License Renewal Progress Energy Electronic Mail Distribution Annette H. Pope, Supervisor Licensing/Regulatory Programs Carolina Power and Light Company Electronic Mail Distribution David T. Conley Associate General Counsel - Legal Dept.

Progress Energy Service Company, LLC Electronic Mail Distribution James Ross Nuclear Energy Institute Electronic Mail Distribution John H. O'Neill, Jr.

Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128 Beverly Hall, Chief, Radiation Protection Section N. C. Department of Environment and Natural Resources Electronic Mail Distribution Peggy Force Assistant Attorney General State of North Carolina Electronic Mail Distribution Chairman of the North Carolina Utilities Commission c/o Sam Watson, Staff Attorney Electronic Mail Distribution Robert P. Gruber Executive Director Public Staff NCUC 4326 Mail Service Center Raleigh, NC 27699-4326

CP&L

Public Service Commission State of South Carolina P. O. Box 11649 Columbia, SC 29211 David R. Sandifer Brunswick County Board of Commissioners P. O. Box 249 Bolivia, NC 28422 Warren Lee Emergency Management Director New Hanover County Department of Emergency Management P. O. Box 1525 Wilmington, NC 28402-1525 Distribution (See page 5)

CP&L

Report to James Scarola from Randal A. Musser dated April 30, 2007.

Distribution w/encl:

S. Bailey, NRR R. Pascarelli, NRR (Regulatory Conferences Only)

C. Evans (Part 72 Only)

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

PUBLIC

U. S. NUCLEAR REGULATORY COMMISSION REGION II Docket Nos:

50-325, 50-324 License Nos:

DPR-71, DPR-62 Report Nos:

05000325/2007002 and 05000324/2007002 Licensee:

Carolina Power and Light (CP&L)

Facility:

Brunswick Steam Electric Plant, Units 1 & 2 Location:

8470 River Road SE Southport, NC 28461 Dates:

January 1, 2007 through March 31, 2007 Inspectors:

E. DiPaolo, Senior Resident Inspector J. Austin, Resident Inspector K. Korth, Inspector-in-Training (1R17, 4OA3)

R. Chou, Reactor Inspector (1R08)

R. Taylor, Reactor Inspector (1R07.2)

H. Gepford, Senior Health Physicist (Sections 2OS2, 2PS1)

A. Nielsen, Health Physicist (Sections 2PS2, 4OA1, 4OA7)

G. Kuzo, Senior Health Physicist (Sections 2OS1)

J. Díaz Vélez, Health Physicist (Sections 2OS1, 4OA1)

Approved by:

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects

SUMMARY OF FINDINGS IR 05000325/2007002, 05000324/2007002; 01/01/07 - 03/31/07; Brunswick Steam Electric Plant, Units 1 and 2; Refueling and Other Outage Activities.

The report covered a 3-month period of inspection by resident inspectors. One self-revealing Green non-cited violation (NCV) 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 4, dated December 2006.

Cornerstone: Initiating Events

Green.

A self-revealing non-cited violation of Technical Specification 5.4.1,

Administrative Controls (Procedures) was identified for failing to follow the Core Component Sequence Sheet for Refueling Outage B218R1 during fuel movement on Unit 2. This resulted in the incorrect fuel assembly being loaded in core location 11-14 which caused an unanalyzed change in core shutdown margin. This issue was entered into the corrective action program for resolution.

The finding was more than minor because it was associated with configuration control of Unit 2 core and affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety function during shutdown as well as power operations. The finding was assessed using the Significance Determination Process for Reactor Inspection Findings for Shutdown Operations and determined to be of very low safety significance (Green) because it did not contribute to a loss of decay heat removal or a loss of reactor coolant system inventory. This finding has a crosscutting aspect of Human Performance, Work Practices, because the incorrect fuel movement was the result of a human error which was not prevented by the use of self and peer checking human error prevention techniques (Section 1R20).

Licensee Identified Violations

Violations of very low safety significance which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program.

The violations are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Unit 1 Unit 1 began the inspection period operating at full power. On January 26, a planned downpower was performed to approximately 70 percent to facilitate main turbine valve testing and a control rod improvement. The unit was returned to full power on January 27. A planned downpower was performed on March 1 to test main turbine valves. Power was returned to full later that day where it remained for the duration of the inspection period.

Unit 2 Unit 2 began the inspection period in power ascension at 87 percent power following a forced outage. Full power was achieved on January 4. On January 28, a planned downpower was performed to approximately 70 percent to facilitate a control rod improvement. Full power was achieved on January 29. On February 2, power was reduced to approximately 93 percent to implement final feedwater temperature reduction. The unit was returned to full power later that day. On March 2, a reactor shutdown was completed to commence Refueling Outage B218R1.

Unit 2 was placed in Mode 5 (Refueling) on March 4. At the end of the inspection period, Unit 2 was in Mode 4 (Cold Shutdown) and preparations were being made to perform reactor coolant system hydrostatic testing.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R04 Equipment Alignment

==

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed three partial walkdowns of the below listed systems to verify that the systems were correctly aligned while the redundant train or system was inoperable or out-of-service (OOS) or, for single train risk significant systems, while the system was available in a standby condition. The inspectors assessed conditions such as equipment alignment (i.e., valve positions, damper positions, and breaker alignment)and system operational readiness (i.e., control power and permissive status) that could affect operability. The inspectors verified that the licensee identified and resolved equipment alignment problems that could cause initiating events or impact mitigating system availability. The inspectors reviewed Administrative Procedure ADM-NGGC-0106, Configuration Management Program Implementation, to verify that available structures, systems or components (SSCs) met the requirements of the configuration control program. Documents reviewed are listed in the Attachment.

• Unit 2 reactor core isolation cooling (RCIC) system when high pressure coolant injection (HPCI) system was OOS on February 2, 2007

• Emergency buses E1, E2, and E3 when emergency bus E4 was OOS for planned maintenance on March 26, 2007

• Unit 2 B loop of residual heat removal (RHR) while in the shutdown cooling mode on March 3, 2007 To assess the licensees ability to identify and correct problems, the inspectors reviewed the following Action Requests (ARs):

• AR 216122216122 Unit 2 RCIC system pump seal saddle drain clogged with debris

• AR 217567217567 Unit 2 oscillation power range monitor alarms during power escalation

• AR 222962222962 EDG #2 and EDG #3 missing bolts on generator cover

b. Findings

No findings of significance were identified.

==1R05 Fire Area Walkdowns

a. Inspection Scope

==

The inspectors reviewed ARs and work orders (WOs) associated with the fire suppression system to confirm that their disposition was in accordance with Administrative Procedure 0AP-033, Fire Protection Program Manual. The inspectors reviewed the status of ongoing surveillance activities to verify that they were current to support the operability of the fire protection system. In addition, the inspectors observed the fire suppression and detection equipment to determine whether any conditions or deficiencies existed which would impair the operability of that equipment. The inspectors toured the following six areas important to reactor safety and reviewed the associated prefire plans to verify that the requirements for fire protection design features, fire area boundaries, and combustible loading were met. Documents reviewed are listed in the Attachment.

• Units 1 and 2 HPCI rooms, -17' elevation (2 areas)

• Units 1 and 2 north and south RHR rooms, -17' elevation (4 areas)

b. Findings

No findings of significance were identified.

==1R07 Heat Sink Performance

==

.1 Annual Review

a. Inspection Scope

The inspectors reviewed activities associated with the inspection and cleaning of the Unit 2 A RHR heat exchanger when oyster growth was discovered in the associated conventional service water header. The issue, discovered during the Unit 2 refueling outage (B218R1), was documented in AR 224737224737 The inspectors observed the results of the inspection conducted in accordance with preventive maintenance procedures.

The inspection results were analyzed to determine if inspection frequencies were adequate to detect degradation prior to loss of heat removal capability below design-basis values. The inspector verified that the licensee appropriately addressed the extent-of-condition of potential oyster growth on other headers of service water, including Unit 1, and the potential effects on supported systems.

b. Findings

No findings of significance were identified

.2 Biennial Heat Sink Performance

a. Inspection Scope

The inspectors reviewed inspection records, test results, maintenance work orders, and other documentation to ensure that heat exchanger (HX) deficiencies that could mask or degrade performance were identified and corrected. Risk significant heat exchangers reviewed included the RHR and the EDGs jacket water HXs.

The inspectors reviewed the GL 89-13 program procedure, inspection and cleaning procedures, completed inspection records, and design specification sheets for the selected safety related HXs. In addition, the inspectors reviewed the thermal performance test procedure that will be used for the EDGs jacket water and RHR HXs.

These documents were reviewed to verify that test methods were consistent with industry standards, and to verify inspection methods and performance of the HXs under the current maintenance frequency were adequate. To verify minimum flow requirements and HX design basis were being maintained, the inspectors reviewed service water (SW) system hydraulic performance test records, acceptance criteria, and HX minimum required flow calculations.

The inspectors also reviewed general health of the SW system via review of design basis documents, system health reports, self assessments, sodium hypochlorite treatment and sampling, and discussions with the SW system engineer. Additionally, SW pipe crawl through inspection results were reviewed. These documents were reviewed to verify design bases were being maintained and to verify adequate SW system performance under current preventive maintenance, chemical treatments, inspections, and frequencies.

Corrective action reports (i.e., ARs) were reviewed for potential common cause problems and problems which could affect system performance to confirm that the licensee was entering problems into the corrective action program and initiating appropriate corrective actions. In addition, the inspectors conducted a walk down of all selected HXs and major components for the SW system to assess general material condition and to identify any degraded conditions of selected components.

b. Findings

No findings of significance were identified.

==1R08 Inservice Inspection Activities

a. Inspection Scope

==

On March 12-16, 2007, the inspectors observed in-process inservice inspection (ISI)work activities on Unit 2, and reviewed selected ISI records. The observations and records were compared to the Technical Specifications (TS) and the applicable Code (ASME Boiler and Pressure Vessel Code,Section XI, 1989 Edition, with no Addenda) to verify compliance.

The inspectors observed in-process ultrasonic (UT) examinations performed on vertical and horizontal welds of the reactor vessel to verify exams were being performed in accordance with the ASME Boiler and Pressure Vessel Code,Section XI. The exams included two vertical welds performed on the upper shell by using automated UT and two vertical and one horizontal welds on the bottom head by using manual UT. The inspectors also observed liquid penetrant examinations (PT) on two main steam isolation valve (MSIV) stem hubs and bonnet areas for the weld build-up. The inspectors reviewed records of the examinations observed and other Magnetic Particle Examinations (MT) including calibrations, equipment certifications, consumable certifications, and personnel qualifications. The welds observed and the documents reviewed were shown as follows:

• Automated UT on Welds 2B11-RPV-E3A & -E2A, Reactor Vessel Upper Shell, ASME Class 1

• Manual UT on Welds 2B11-RPV-H & 2B11-RPV-G3 & -G4, Reactor Vessel Bottom Head, ASME Class 1

• PT on Welds FW #5, MSIV A & FW #6, MSIV C, ASME Class 1 The inspectors also reviewed documents as follows:

• PT on Bonnet Weld Build-Up 2-B21-F028C for MSIV C

• PT on Welds 2-C12-2615, 2-C12-2593, & 2-C12-2575, CRD Housing

• PT on Weld 2-B32-3018, RCR Integral Attachment

• MT on Weld 2-B21-2025, MS Integral Attachment

• MT on Weld 2-B21-3000, FW Integral Attachment The inspectors reviewed a previous PT report (PT-06-001) which documented recordable indications on integral attachment welds of the reactor recirculation pump 1A.

The inspectors also observed in-process PT and reviewed the work order package 1010391-01 for the weld repair FW #5 on Valve 2-B21-F028A of MSIV A & the work order package 1026031-01 for the weld repair FW #6 on Valve 2-B21-F028C of MSIV C, ASME Class 1.

The inspectors reviewed four samples of ISI related issues, ARs 00155086, 00188762, 00195541, and 00210270, in the licensees corrective action program to confirm that problems were being identified and placed in the corrective action program, and appropriate corrective actions were being initiated.

b. Findings

No findings of significance were identified.

==1R11 Licensed Operator Requalification

a. Inspection Scope

==

The inspectors observed licensed operator performance and reviewed the associated training documents during simulator training sessions for training cycle 2007-01. The simulator observations and review included evaluations of emergency operating procedure and abnormal operating procedure utilization. The inspectors reviewed Procedure 0TPP-200, Licensed Operator Continuing Training Program, to verify that the program ensures safe power plant operation. Simulator training sessions were observed on February 15, 2007. The scenarios tested the operators ability to respond to various instrumentation failures, abnormal operating transients, and accidents. The inspectors reviewed operator activities to verify consistent clarity and formality of communication, conservative decision-making by the crew, appropriate use of procedures, and proper alarm response. Group dynamics and supervisory oversight, including the ability to properly identify and implement appropriate TS actions, regulatory reports, and notifications, were observed. The inspectors observed instructor critiques and preliminary grading of the operating crews and assessed whether appropriate feedback was planned to be provided to the licensed operators.

b. Findings

No findings of significance were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the two equipment issues described in the ARs listed below, the inspectors reviewed the licensees implementation of the Maintenance Rule (10 CFR 50.65) with respect to the characterization of failures, the appropriateness of the associated Maintenance Rule a(1) or a(2) classification, and the appropriateness of the associated a(1) goals and corrective actions. The inspectors reviewed the work controls and work practices associated with the degraded performance or condition to verify that they were appropriate and did not contribute to the issue. The inspectors also reviewed operations logs and licensee event reports to verify unavailability times of components and systems, if applicable. Licensee performance was evaluated against the requirements of Procedure ADM-NGGC-0101, Maintenance Rule Program.

• AR 224833224833 Unit 2 HPCI pump outboard bearing found damaged.

• AR 220519220519 Emergency bus E1 to E3 crosstie breaker on E1 discovered in a nonfunctional condition due to improper breaker rack-in

b. Findings

No findings of significance were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors reviewed the licensees implementation of 10 CFR 50.65 (a)(4)requirements during scheduled and emergent maintenance activities, using Procedure 0AP-025, BNP Integrated Scheduling and Technical Requirements Manual 5.5.13, Configuration Risk Management Program. The inspectors reviewed the effectiveness of risk assessments performed due to changes in plant configuration for maintenance activities (planned and emergent). The review was conducted to verify that, upon unforeseen situations, the licensee had taken the necessary steps to plan and control the resultant emergent work activities. The inspectors reviewed the applicable plant risk profiles, work week schedules, and maintenance WOs for the following five conditions:

• AR 217566217566 Unit 2 A RHR loop pressurization cause elevated (yellow) risk due to inability to remotely align to suppression pool cooling mode on January 1, 2007 (emergent)

• AR 219636219636 Realign Units 1 and 2 HPCI and RCIC suction source from the condensate storage tank to the suppression pool due to foreign material found in condensate storage tank on January 18, 2007 (emergent)

• WO 687263, Unit 1 A RHR OOS for planned maintenance on January 25, 2007

• AR 220603220603 EDG #1 auto voltage regulator position limit switch found loose on January 29, 2007 (emergent)

• AR 227196227196 Elevated risk condition due to planned maintenance outage on emergency buses E4 and E8 on March 26, 2007 To assess the licensees ability to identify and correct problems, the inspectors reviewed the following ARs:

• AR 218258218258 Unit 1 B reactor feed pump speed control cabinet trouble alarm

• AR 218246218246 Unit 1 B 250 volt battery ground

• AR 217566217566 Unit 1 A RHR loop pressurization causes suppression pool cooling mode inoperability

• AR 224331224331 Unit 1 EDG #1 and EDG #2 reliability exceed station blackout goals

• AR 225175225175 Unit 1 B recirculation motor-generator set standby lubricating oil pump failed to start

b. Findings

No findings of significance were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed the operability evaluations associated with the six issues documented in the ARs listed below, which affected risk significant systems or components, to assess, as appropriate: 1) the technical adequacy of the evaluations; 2)the justification of continued system operability; 3) any existing degraded conditions used as compensatory measures; 4) the adequacy of any compensatory measures in place, including their intended use and control; and 5) where continued operability was considered unjustified, the impact on any TS limiting condition for operation and the risk significance. In addition to the reviews, discussions were conducted with the applicable system engineer regarding the ability of the system to perform its intended safety function.

• AR 222140222140 Unit 1 C conventional service water pump motor stator high temperatures

• AR 219724219724 Lack of periodic calibration on reactor feedwater resistance temperature detectors

• AR 219636219636 Foreign material found in Unit 2 condensate storage tank

• AR 219625219625 High temperatures on EDG #2 and #3 generator pedestal bearings

• AR 223012223012 EDG Allen Bradley control relay failures due to age degradation

• AR 221768221768 EDG control air shuttle valve elastomer age degradation To assess the licensees ability to identify and correct problems, the inspectors reviewed the following ARs:

• AR 217492217492 EDG #1 control air pressure regulating valve controlling pressure high

• AR 221503221503 EDG #4 control air pressure control regulating valves installed backwards

• AR 219466219466 EDG #3 service water temperature differential increase across jacket water cooler heat exchanger

b. Findings

No findings of significance were identified.

==1R17 Permanent Plant Modifications

a. Inspection Scope

==

The inspectors reviewed two permanent plant modifications documented in the below listed documents. The inspectors reviewed the design adequacy of the modifications for material compatibility which included functional properties, environmental qualification, and seismic evaluation. The review verified that the modifications were consistent with the plants design bases and the design assumptions. Where applicable, the review verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions and key safety functions. Post-modification testing was reviewed to confirm that operability would be established, unintended system interactions would not occur, and the testing demonstrated that modification acceptance criteria were met. Documents reviewed are listed in the

. The following modifications were reviewed:

C Engineering Change (EC) 60313, Chlorine Detector System Replacement C

Engineering Change (EC) 61681, Increase Main Steam Isolation Valve Allowable Leakage

b. Findings

No findings of significance were identified. However, one licensee-identified violation was identified and discussed in Section 4OA7 of this report.

==1R19 Post-Maintenance Testing

a. Inspection Scope

==

For the five maintenance activities listed below, the inspectors reviewed the post-maintenance test procedure and witnessed the testing and/or reviewed test records to confirm that the scope of testing adequately verified that the work performed was correctly completed. The inspectors verified that the test demonstrated that the affected equipment was capable of performing its intended function and was operable in accordance with TS requirements. The inspectors reviewed the licensees actions against the requirements in Procedure 0PLP-20, Post Maintenance Testing Program.

• WO 1009389, EDG #1 auto voltage regulator position limit switch found loose

• WO 1019094, EDG #2 trip due to failure of low lubricating oil pressure trip relay (LPSCR)

• WO 791521, Replace EDG #4 starting air header pressure control valves

• WO 1036962, Troubleshoot and repair Run Control relay malfunction on EDG #4

• WO 1010391, Install valve disc guide pad modification on Unit 1 A outboard main steam isolation valve (2-B21-F028A)

To assess the licensees ability to identify and correct problems, the inspectors reviewed the following ARs:

• AR 223349223349 Loss of control power to Unit 2 D RHR pump during post-maintenance run

• AR 220841220841 Unit 2 B reactor protection system motor-generator set high noise upon startup

b. Findings

No findings of significance were identified.

==1R20 Refueling and Other Outage Activities Unit 2 Refueling Outage B218R1

a. Inspection Scope

==

The inspectors evaluated Unit 2 Refueling Outage (RFO) B218R1 activities which commenced on March 2, 2007. At the end of the inspection period, Unit 2 was in Mode 4 (Cold Shutdown) with preparations being made for startup. Documents reviewed are listed in the Attachment. The following specific areas were reviewed:

Outage Plan. The inspectors reviewed Brunswick Nuclear Plant Unit 2 Safe Shutdown Risk Assessment, for RFO B218R1. The inspectors verified that the licensee had considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors review of this report was compared to the requirements in Procedure 0AP-022, BNP Outage Risk Management. The review verified that for identified high risk significant conditions, contingency measures were identified. The inspectors frequently monitored the risk condition during the outage.

Shutdown and Cooldown. The inspectors observed portions of the Unit 2 shutdown to enter the outage to verify that activities were in accordance with General Procedure 0GP-5.0, Unit Shutdown. The inspectors verified that the licensee monitored cooldown restrictions by performing 2PT-01.7, Heatup/cooldown Monitoring, to assure that TS cooldown restrictions were satisfied.

Licensee Control of Outage Activities. The inspectors observed and reviewed several specific activities, evolutions, and plant conditions to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan. The inspectors reviewed configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan. The inspectors reviewed the following specific items, as specified:

• Decay Heat Removal, Spent Fuel Pool Cooling, and Reactor Coolant System Instrumentation. The inspectors reviewed decay heat removal procedures and observed decay heat removal systems parameters to verify proper removal of decay heat and that reactor vessel level instruments were configured to provide accurate indication. The inspectors also conducted main control room panel walkdowns and walked down portions of the systems in the plant to verify system availability. The inspectors reviewed operational logs to verify that procedure and TS requirements to monitor and record reactor coolant temperature were met.

• Reactivity Control. The inspectors observed licensee performance during shutdown, outage, and refueling activities to verify that reactivity control was conducted in accordance with procedures and TS requirements. The inspectors conducted a review of outage activities and risk profiles to verify activities that could cause reactivity control problems were identified.

• Inventory Control and Containment Closure. The inspectors observed operator monitoring and control of reactor temperature and level profiles and monitored outage work and configuration control for activities that had the potential to drain the reactor vessel. This was performed to verify that they were performed in accordance with the outage risk plan. The inspectors verified that the licensee maintained secondary containment in accordance with TS.

• Electrical Power. The inspectors reviewed the following licensee activities related to electrical power during the refueling outage to verify that they were in accordance with the outage risk plan:

• Controls over electrical power systems and components to ensure emergency power was available as specified in the outage risk report

• Controls and monitoring of electrical power systems and components and work activities in the power transmission yard

• Operator monitoring of electrical power systems and outages to ensure that TS requirements were met Refueling Activities. The inspectors reviewed refueling activities to verify fuel handling operations were performed in accordance with TS and fuel handling procedures and that controls were in place to track fuel movement. The inspectors reviewed refueling floor and plant controls to verify that the foreign material exclusion controls were established.

Identification and Resolution of Problems. The inspectors reviewed ARs to verify that the licensee was identifying problems related to refueling outage activities at an appropriate threshold and entering them in the corrective action program. The inspectors attended AR review meetings throughout the refueling outage to verify appropriate prioritization of planned resolution of deficiencies discovered during the outage. The inspectors reviewed the following issues identified during the outage to verify that the appropriate corrective actions were implemented:

• AR 226329226329 Supplemental spent fuel pool cooling secondary loop flow reduction

• AR 226387226387 Unit 2 A reactor feed pump diffuser erosion

• AR 226703226703 Unit 2 B reactor feed pump apparent crack in casing

• AR 225888225888 Foreign material found during bottom head inspection

• AR 224481224481 Local leak rate test failure on main steam isolation valve 2-B21-F028A

• AR 227090227090 Fuel support casting at core position 26-07 not seated properly

• AR 227656227656 Unit 2 B RHR pump leak at seal cavity flange

• AR 224482224482 Unit 2 source range monitor A and C spiking

• AR 224393224393 Main turbine removed from service during power reduction due to high bearing vibration

• AR 225007225007 Erosion discovered on 20 inch service water flange 2-E11-PDV-F068A

• AR 225247225247 Unit auxiliary transformer non-segregated flex link inspection discrepancies

b. Findings

Introduction.

A self-revealing Green NCV of Technical Specification 5.4.1 was identified for failure to follow a core alteration procedure which resulted in the incorrect fuel assembly being moved into the Unit 2 core from the spent fuel pool.

Description.

During refueling operations on March 20, 2007, refueling bridge operators found that the fuel assembly required to be moved from spent fuel pool rack D4 location B1 (D4B1) to the Unit 2 core, per Step 478 of the Core Component Sequence Sheet for Refueling Outage B218R1, was not present in the specified rack location. Refueling operations were suspended to investigate the apparent discrepancy.

The licensees investigation found that the fuel assembly at rack location D4B1 (fuel assembly JLS640) had been moved at Step 437 of the Core Component Sequence Sheet in error. Step 437 required the fuel assembly (JLS674) at spent fuel rack D3 location B1 (D3B1) to be moved to core location 11-14. Core location 11-14 was found to contain the incorrect fuel assembly (JLS640). The refueling bridge operators that performed Step 437, the same operator that discovered that location D4B1 did not contain a fuel assembly, apparently moved the fuel assembly at rack location D4B1 vice D3B1, as required by Step 437.

The licensee convened a human performance review board to investigate the error.

The board concluded that there were two most probable causes. The first probable cause was that a mis-communication between bridge operators occurred with the direction to move the bridge to D3B1 rather than D4B1. The team may have then moved the bridge to the named location, correctly verified the position, and then performed the move. For this to have occurred, the discrepancy between the Core Component Sequence Sheet and the rack location would have been made by two people. The second probable cause was that the bridge was mis-positioned over the incorrect location and incorrectly verified. This would have required two people to have made the same mistake of miscounting fuel racks.

In addition, the licensees immediate corrective actions included the following: 1) An extent-of-condition review of the core and spent fuel pool verified that the movement error was an isolated event; 2) Core shutdown margin was recalculated and found to be adequate (.091% reduction); 3) The Unit 2 Core Component Sequence Sheet for Refueling Outage B218R1 was revised to reflect the core and spent fuel pool configuration; and 4) Refueling crew stand-downs were held to review the event and reemphasize the expectations the use of human performance reduction tools.

Analysis.

The failure to follow the Unit 2 Core Component Sequence Sheet for Refueling Outage B218R1 is a performance deficiency which resulted the incorrect fuel assembly being loaded in core location 11-14. This resulted in an unanalyzed change in core shutdown margin. The finding was more than minor because it was associated with configuration control of Unit 2 core and affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety function during shutdown as well as power operations. The finding was assessed using the Significance Determination Process for Reactor Inspection Findings for Shutdown Operations and determined to be of very low safety significance (Green)because it did not contribute to a loss of decay heat removal or a loss of reactor coolant system inventory. This finding has a crosscutting aspect of Human Performance, Work Practices, because the incorrect fuel movement was the result of a human error which was not prevented by the use of self and peer checking human error prevention techniques. This finding is in the licensees corrective action program (CAP) as AR 215809215809

Enforcement.

Technical Specification 5.4.1, Administrative Control (Procedures),requires that written procedures shall be implemented covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33 requires written procedures for performing core alterations. Fuel Handling Procedure 0FH-11A, Refueling Platform Operations, Revision 59, requires that components be moved in accordance with Form 0ENP-24.12-3, Core Component Sequence Sheet. Step 437 of Unit 2 Core Component Sequence Sheet for Refueling Outage B218R1 required fuel assemble JLS674 at spent fuel location D3B1 to be moved to core coordinate 11-14. Contrary to Step 437, fuel assembly JLS640 at spent fuel location D4B1 was moved to core coordinate 11-14 in March 2007. As a result, core shutdown margin was slightly reduced. Because the finding is of very low safety significance and has been entered into the CAP (AR 226451226451, this finding is being treated as an NCV, consistent with Section VI.A of the Enforcement Policy. This matter is identified as NCV 05000325/2007002-01, Incorrect Fuel Assembly Moved to Core.

==1R22 Surveillance Testing

==

.1 Routine Surveillance Testing

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed test data for the four risk significant SSC surveillances, listed below, to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing (IST) requirements, and licensee procedural requirements. The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions.

• Periodic Test 0PT-06.1, Standby Liquid Control System Operability Test, performed on Unit 1

• Periodic Test 0PT-20.3a.5, Main Steam Isolation Valve Leak Test (containment isolation valve), performed on Unit 2

• Operating Instruction 0OI-03.4, Unit 0 Outside Auxiliary Operator Daily Checks

• Periodic Test 0PT-10.1.9, Reactor Core Isolation Cooling System Valve Operability Test, performed on Unit 1 To assess the licensees ability to identify and correct problems, the inspectors reviewed the following ARs:

• AR 217684217684 Long filter times associated with EDG fuel oil samples

• AR 220528220528 Diesel-driven fire pump battery cells found with low specific gravity

• AR 222832222832 Instrument calibration issues associated with daily surveillance checks

• AR 220445220445 Foreign material found in Unit 1 standby liquid control tank

b. Findings

No findings of significance were identified.

.2 In-service Surveillance Testing

a. Inspection Scope

The inspectors reviewed the performance of Periodic Test 0PT-12.4A, No. 1 Emergency Diesel Generator Fuel Oil Transfer Pump Test. The inspectors evaluated the effectiveness of the licensees American Society of Mechanical Engineers (ASME)

Section XI testing program to determine equipment availability and reliability. The inspectors evaluated selected portions of the following areas: 1) testing procedures; 2)acceptance criteria; 3) testing methods; 4) compliance with the licensees IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6) required corrective actions. The inspectors also assessed any applicable corrective actions taken.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control To Radiologically Significant Areas

a. Inspection Scope

Access Controls The inspectors reviewed and evaluated licensee guidance and its implementation for controlling and monitoring worker access to radiologically significant areas and tasks associated with Unit 1 (U1) and Unit 2 (U2) operations and the U2 Cycle 18 Refueling Outage (B218R1). The inspectors evaluated changes to, and adequacy of, procedural guidance; directly observed implementation of established administrative and physical radiation controls; appraised radiation worker (radworker)and health physics technician (HPT) knowledge of, and proficiency in, implementing radiation protection (RP) activities; and assessed radworker exposures to radiation and radioactive material.

The inspectors directly observed controls established for radworker and HPT staff in actual or potential airborne radioactivity area, radiation area, high radiation area (HRA),locked high radiation area (LHRA), and very high radiation area (VHRA) locations.

Established radiological controls were evaluated for selected B218R1 tasks including snubber maintenance, U2 recirculation pump seal replacement, U2 "A" feed water pump quality assurance activities, fuel movement, control rod drive mechanism (CRDM)removal and replacement, torus diving, and outage equipment processing and packaging. In addition, licensee controls for drywell and other areas where dose rates could change significantly as a result of plant shutdown and/or refueling operations were reviewed and discussed with cognizant licensee personnel.

For selected tasks, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements to workers. Radworker adherence to selected RWPs and HPT proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Direct reading dosimeter (DRD) equipment alarm set-points were evaluated against area radiation survey results for snubber activities, fuel movement, under-vessel maintenance activity, and CRDM removal and replacement. Worker exposure as measured by DRD and via licensee evaluations of skin doses resulting from discrete radioactive particle or dispersed skin contamination events during current B218R1 activities were reviewed and assessed independently.

The inspectors walked down the U1 and U2 spent fuel pool (SFP) areas to determine if appropriate controls were applied to materials and equipment stored in the pools. The inspectors also reviewed the inventory of items stored in the pools. Controls and their implementation for LHRAs and for storage of irradiated material within the U1 and U2 SFPs were reviewed and discussed in detail.

Postings and physical controls established within the radiologically controlled area for access to the U2 drywell and torus, U1 and U2 reactor building and turbine building locations, and radioactive waste processing and storage facilities were evaluated directly during facility tours. The inspectors independently measured radiation dose rates associated with selected U1 and U2 reactor building areas, U2 drywell areas, and radioactive waste processing areas/equipment. In addition, the inspectors directly observed conduct of licensee surveys and reported radiation levels, airborne radionuclide concentrations, and/or surface contamination levels for selected areas and equipment associated with CRDM removal/replacement, under-vessel tasks, resin processing, recirculation and feedwater pump maintenance activities, and radioactive material shipping activities. Results were compared to current licensee surveys and assessed against established postings and established radiation controls.

The inspectors evaluated implementation and effectiveness of licensee controls for both airborne and external radiation exposures. The inspectors reviewed and discussed selected whole-body count analyses conducted between July 1, 2006, and March 20, 2007, to evaluate implementation and effectiveness of personnel monitoring and administrative and physical controls including air sampling, barrier integrity, engineering controls, and postings for tasks having the potential for individual worker internal exposures to exceed 30 millirem committed effective dose equivalent. Effectiveness of external radiation exposure controls were evaluated through review and discussion of individual worker dose as measured by DRD between July 1, 2006, and March 20, 2007, for selected non-outage and current B218R1 tasks.

RP activities were evaluated against Updated Final Safety Analysis Report (UFSAR),

Technical Specifications (TS), and 10 CFR Parts 19 and 20 requirements. Specific assessment criteria included UFSAR Section 12, Radiation Protection; 10 CFR 19.12; 10 CFR 20, Subparts B, C, F, G, H, and J; TS Sections 5.4, Procedures and 5.7, High Radiation Area; and approved licensee procedures. Licensee guidance documents, records, and data reviewed within this inspection area are listed in Section 2OS1, 2OS2, 2PS2, and 4OA1 of the report Attachment.

Problem Identification and Resolution The inspectors reviewed and assessed select Action Request (AR) documents associated with access control to radiologically significant areas. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-0200, Corrective Action Program, Rev. 19. In addition, the inspectors reviewed self-assessments conducted in regard to access controls. Specific corrective action program (CAP) documents associated with access control issues, personnel radiation monitoring, and personnel exposure events reviewed and evaluated during inspection of this program area are identified in Section 2OS1 of the report Attachment.

The inspectors completed 21 of the required line-item samples described in Inspection Procedure (IP) 71121.01.

b. Findings

No findings of significance were identified.

2OS2 As Low As Reasonably Achievable (ALARA) Planning and Controls

a. Inspection Scope

ALARA The inspectors reviewed ALARA program guidance and its implementation for ongoing B218R1 job tasks. The inspectors evaluated the accuracy of ALARA work planning and dose budgeting, observed implementation of ALARA initiatives and radiation controls for selected jobs in-progress, assessed the effectiveness of source-term reduction efforts, and reviewed historical dose information.

ALARA Work Plans (AWPs) and procedural guidance were reviewed and projected hours and dose estimates were compared to actual dose and hour expenditures for the following high dose jobs performed during B218R1: scaffolding, refuel floor activities, circulating water maintenance, CRD exchange, and safety relief valve maintenance. In addition, AWPs, including In-Progress and Post-Job Reviews, for jobs performed during previous outages or online were reviewed: U1/U2 double blade guide disposal and modification, U2 2-B32-FO31B recirculation valve repair, Unit 1-A south condenser tube leak repair, B217R1 (U2 Cycle 17 Refueling Outage) scaffolding, and B217R1 refuel floor activities. Differences between budgeted dose and actual exposure received were discussed with cognizant ALARA staff and project managers. In-progress reviews and methodology for revising dose estimates relative to changes in radiation source term and/or job scope were also discussed. The inspectors attended pre-job briefings and evaluated the communication of ALARA goals, RWP requirements, and industry lessons-learned to responsible personnel. The inspectors attended three ALARA committee meetings in which AWPs and requests for revised dose budgets subsequent to In-Progress Reviews were reviewed and approved.

The inspectors made direct field or closed-circuit-video observations of outage job tasks involving torus diving, snubber maintenance, U2 recirculation pump seal replacement, U2 "A" feed water pump quality assurance activities, U2 condenser maintenance, fuel movement, and outage equipment processing and packaging. For the selected tasks, the inspectors evaluated radworker and HPT job performance, individual and collective dose expenditure versus percentage of job completion, surveys of the work areas, appropriateness of RWP requirements, and adequacy of implemented engineering controls. For selected tasks, the inspectors interviewed radworkers and job sponsors regarding understanding of dose reduction initiatives and their current and expected accumulated doses at completion of the job tasks.

Implementation and effectiveness of selected source-term reduction program initiatives were evaluated. The Brunswick Nuclear Plant ALARA Continuous Improvement Strategy (2005), ALARA Continuous Improvement Strategy Interim Update (2006), and planned initiatives related to residual heat removal and recirculation piping source term reduction, cobalt reduction, and reactor water cleanup system efficiency improvements, were reviewed and discussed with cognizant licensee personnel. Chemistry and maintenance program ALARA efforts and their effect on U2 drywell dose rate trends were reviewed.

Plant exposure history for calendar year (CY) 2001 through CY 2006 and data reported to the NRC pursuant to 10 CFR 20.2206 were reviewed, as were established goals for reducing collective exposure during the current B218R1 outage. The inspectors reviewed procedural guidance for dosimetry issuance and exposure tracking. The inspectors also reviewed selected individual access records for dose received during work in areas with high dose rates and dose rate gradients. In addition, dose records of declared pregnant workers were examined to evaluate assignment of doses to the radworker and embryo/fetus.

ALARA program activities and their implementation were reviewed against 10 CFR Part 20 and approved licensee procedures. In addition, licensee performance was evaluated against guidance contained in Regulatory Guide (RG) 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Stations will be As Low As Reasonably Achievable and RG 8.13, Instruction Concerning Prenatal Radiation Exposure. Procedures and records reviewed within this inspection area are listed in Sections 2OS1 and 2OS2 of the report Attachment.

Problem Identification and Resolution The inspectors reviewed selected AR, audit, and self-assessment documents in the area of ALARA program implementation. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-0200, Corrective Action Program, Rev. 19. Specific CAP documents reviewed in detail for this inspection area are identified in Section 2OS2 of the report Attachment.

The inspectors completed 22 of the required line-item samples described in IP 71121.02.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety (PS)

2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems

a. Inspection Scope

Groundwater Monitoring Current licensee programs for monitoring, tracking, and documenting the results of both routine and abnormal liquid releases to the onsite and offsite surface and groundwater environs were reviewed. The inspectors discussed current and planned actions for onsite groundwater monitoring with supervisors and managers in the Environmental and Chemistry departments, including number and placement of monitoring wells and identification of plant systems with the greatest potential for contaminated leakage. In addition, the inspectors reviewed procedural guidance for identifying and assessing onsite spills and leaks of contaminated fluids.

Radionuclide concentration results for onsite groundwater monitoring wells and select manwells were reviewed.

In 1995, a ground water study was performed following a release from the U2 Radwaste Effluent Line. The current applicability of this study was reviewed and verified in 2006.

Currently, the licensee maintains ten onsite groundwater monitoring wells with samples taken at various frequencies. Analyses are performed for tritium and, for selected samples, primary gamma emitters. To date, tritium has been the only radionuclide identified in the well samples. In addition, the Recovery Pond and Gum Log Branch are sampled for surface water tritium.

Leaks from the U2 Radwaste Effluent Line were identified and repaired in 1987 and 1994. Tritium has been identified in two monitoring wells adjacent to the U2 Radwaste Effluent Line; no levels exceeding NRC or Environmental Protection Agency (EPA) limits have been reported in the offsite environs. Recently, upon reducing the lower limit of detection, low-level tritium activity was identified in an additional well.

The inspectors completed two of the required line-item samples described in IP 71122.01.

b. Findings

No findings of significance were identified.

2PS2 Radioactive Material Processing and Transportation

a. Inspection Scope

Waste Processing and Characterization During inspector walkdowns, accessible sections of the liquid and solid radioactive waste (radwaste) processing systems were assessed for material condition and conformance with system design diagrams.

Inspected equipment included waste storage tanks, resin transfer piping, resin packaging and dewatering components, and abandoned centrifuge equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with system operators.

The 2005 Effluent Report and the last two radionuclide characterizations for each major waste stream were reviewed and discussed with radwaste staff. For resinous waste and dry active waste the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing and concentration averaging methodology was evaluated and discussed with shipping/radwaste staff. The inspectors also reviewed the licensees program for monitoring changes in waste stream isotopic mixtures.

Radwaste processing activities and equipment configuration were reviewed for compliance with the licensees Process Control Program and UFSAR, Chapter 11.

Waste stream characterization analyses were reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch Technical Position on Waste Classification and Waste Form. Reviewed documents are listed in Section 2PS2 of the report Attachment.

Transportation The inspectors directly observed preparation activities for shipments of outage equipment and resin. The inspectors noted package markings and placarding, performed independent dose rate measurements, and interviewed shipping technicians regarding Department of Transportation (DOT) regulations.

Five shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed shipping paper emergency response information, DOT shipping package classification, NRC waste classification, radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Records of spent fuel shipments were evaluated for adherence to Certificate of Compliance requirements. Licensee procedures for handling Type A shipping casks were compared to recommended vendor protocols. In addition, training records and training curricula for selected individuals currently qualified to ship radioactive material were reviewed.

Transportation program implementation was reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 71, 49 CFR Parts 172-178, as well as the guidance provided in NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H. Documents reviewed during the inspection are listed in Section 2PS2 of the report Attachment.

Problem Identification and Resolution Selected ARs in the area of radwaste/shipping were reviewed in detail and discussed with licensee personnel. The inspectors assessed the licensees ability to characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-0200, Corrective Action Program, Rev. 19. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent self-assessment results. Documents reviewed for problem identification and resolution are listed in Section 2PS2 of the report Attachment.

The inspectors completed six of the required line-item samples described in IP 71122.02.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data for the performance indicators (PIs) listed below.

To verify the accuracy of the PI data reported during the period reviewed, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev.

4 were used to verify the basis for each data element.

Reactor Safety Cornerstone The inspectors sampled licensee submittals for the Units 1 and 2 PIs listed below for the period January 2006 through December 2006.

• Unplanned Scrams per 7000 Critical Hours

• Scrams with Loss of Normal Heat Removal

• Unplanned Power Changes per 7000 Critical Hours A sample of plant records and data was reviewed and compared to the reported data to verify the accuracy of the PIs. The licensees corrective action program records were also reviewed to determine if any problems with the collection of PI data had occurred.

Documents reviewed are listed in the Attachment.

Occupational Radiation Safety Cornerstone The inspectors reviewed the Occupational Exposure Control Effectiveness PI results from July 2006 through March 2007. For the assessment period, the inspectors reviewed electronic dosimeter alarm logs and assessed CAP records to determine whether HRA, VHRA, or unintended radiation exposures had occurred. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. In addition, the inspectors reviewed selected personnel contamination event data and internal dose assessment results. Report section 2OS1 contains additional details regarding the inspection of controls for exposure significant areas. Documents reviewed are listed in sections 2OS1, 2OS2, 2PS2, and 4OA1 of the report Attachment.

Public Radiation Safety Cornerstone The inspectors reviewed the Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from July 2006 through December 2006. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. The inspectors also discussed collection and analysis of PI data with licensee personnel. Reviewed documents are listed in Section 4OA1 of the report Attachment.

The inspectors completed five of the required samples described in IP 71151.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of ARs

To aid in the identification of repetitive equipment failures or specific human performance issues for followup, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily ARs.

.2 Annual Sample Review

a. Inspection Scope

The inspectors performed an in-depth annual sample review of the below-listed issues as documented in licensee correction action documents to verify that conditions adverse to quality were addressed in a manner that was commensurate with the safety significance of the issue. The inspectors reviewed the actions taken to verify that the licensee had adequately addressed the following attributes:

• Complete, accurate, and timely identification of the problem

• Evaluation and disposition of operability and reportability issues

• Consideration of previous failures, extent of condition, generic or common cause implications

• Prioritization and resolution of the issue commensurate with the safety significance

• Identification of the root cause and contributing causes of the problem

• Identification and implementation of corrective actions commensurate with the safety significance of the issue The inspectors reviewed the following issues:

• AR 212509212509 Unit 2 condenser tube leaks due to expelled condenser tube plugs during a loss of offsite power event

• AR 211474211474 EDG #2 and #3 generator pedestal bearing high temperature during the November 1, 2006 loss of offsite power event

b. Findings and Observations

No findings of significance were identified.

4OA3 Event Follow-up

.1 Personnel Performance during Plant Evolutions

a. Inspection Scope

The inspectors reviewed the operator response to a feedwater transient which occurred on Unit 2 during preparations for reactor shutdown for refueling outage on March 2, 2007. To assess operator performance during the transient, the inspectors reviewed operator logs, plant computer data, associated operator actions as well as Abnormal Operating Procedure 23, Condensate/Feedwater Failure.

b. Findings

No findings of significance were identified.

.2 (Closed) LER 05000324/2006001:

Loss of Startup Auxiliary Transformer Results in Unit 2 Manual Reactor Protection System Actuation.

On November 1, 2006, Unit 2 experienced a loss of the Startup Auxiliary Transformer (SAT) resulting in a loss of reactor forced circulation and initiation of a manual reactor protection system actuation. Loss of the SAT was caused by an ineffective mechanical connection, made during original construction, between the SAT's x-winding nonsegregated bus and the associated bus bar which caused overheating. The affected flexible link and bus bar connection were repaired and the adjacent flexible links were inspected to confirm they were not damaged. Additional corrective actions, completed or planned, include implementation of enhanced predictive maintenance requirements that will include thermography inspections and trending of all Unit 1 and Unit 2 nonsegregated buses; installation of infrared windows at the non-segregated bus flexible links to aid in visual and thermographic inspection on both units; and de-terminate, clean inspect and restore other Unit 1 and Unit 2 flexible link connections.

The LER was reviewed by the inspectors and no findings of significance were identified and no violation of NRC requirements occurred. The licensee documented the failed equipment in AR 211212211212 This LER is closed.

.3 (Closed) LER 05000324/2006002:

Manual Scram Due to Conductivity Increase.

On November 11, 2006, Unit 2 was in Mode 2 recovering from a forced outage following a Loss of Offsite Power (LER 05000324/2006001). During plant startup and heatup, the plant experienced high conductivity in the condenser. Operators terminated the startup by inserting a manual scram. The high conductivity in the condenser was determined to be the result of missing plugs on 165 condenser tubes, of which 17 were found to have leaks. The licensee determined that during a LOOP event, circulating pumps stop and the condenser experiences a thermal transient. Plugged tubes that have moisture in them (e.g., due to tube leakage) undergo a pressure buildup which can be sufficient to expel the plugs from the tubes. A similar event occurred on Unit 1 following a LOOP in 2004 where 95 tubes were found to have had their plugs ejected (AR 135131135131. The corrective actions from the Unit 1 event were ineffective in preventing this repeat occurrence. The water boxes were opened and all missing plugs were reinstalled.

Additional corrective actions, completed or planned, include revising the post-trip review procedure to include a statement that following a LOOP, loss of vacuum or loss of circulating flow, the water boxes should be inspected for missing tube plugs; and installing a different type of condenser tube plug at strategic locations, that is less susceptible to this failure mode. The inspectors determined that this event represented a finding of minor significance where inadequate corrective actions had been taken following the 2004 Unit 1 event. The licensee documented the event in AR 212509212509

This LER is closed.

.4 (Closed) LER 05000325,324/2006003:

Control Room Emergency Ventilation (CREV)

System Inoperable due to Chlorine Detection Modification Deficiency.

Early in April 2006, simulator scenarios revealed that the response of the chlorine detectors was negating the auto-start function of the CREV System in radiation protection mode. This was communicated by the Training Staff to Engineering and on April 10, 2006, Engineering notified Operations of the CREV design modification deficiencies in February and March 2006. The system was declared inoperable and action was initiated to remove the chlorine tank from the plant chlorine exclusion area and disable the chlorine detectors. The chlorine tank was removed, the chlorine detectors were disabled and the Limiting Condition for Operation (LCO) was exited.

Other corrective actions included: development of a Supervisor Human Performance Consideration checklist to help ensure new error likely situations/error precursors that may have occurred during the design process are recognized and appropriately addressed prior to the approval of the EC; the 10 CFR 50.59 evaluation for the chlorine detector replacement was revised; and a design modification was initiated for the chlorine detectors to prevent the detectors from re-powering in an actuated state. The licensees root cause of the design deficiency was failure to follow Nuclear Generation Group Standard Procedure, EGR-NGGC-0005, Engineering Change, which requires that changes made in response to review comments that may affect other reviewers are communicated to those reviewers. Had the system engineer been aware of the potential of the system to re-power in the chlorine protection mode following a LOOP, his review of the EC for establishing automatic actuation of the system in radiation mode within two minutes would probably have identified the design conflict.

The inspectors determined that this issue was greater than minor because it affected the Barrier Integrity Cornerstone objective of maintaining the radiological barrier functionality of control room. A Phase 1 Significance Determination Process review screened the finding as very low safety significance (Green) based on the finding only representing a degradation of the radiological barrier function provided for the control room. The licensee entered the deficiency with the design control process into their corrective action program for resolution (AR 190868190868. The enforcement aspects of this issue are discussed in Section 4OA7. This LER is closed.

.5 (Closed) LER 05000325,324/2006005: Control Room Emergency Ventilation (CREV)

System Inoperable due to Chlorine Detectors.

On August 6, 2006, the CREV System unexpectedly realigned to the chlorine protection mode during an EDG surveillance run. The cause of the CREV system realignment was due to sensitivity of the new chlorine detectors to nitrogen dioxide (NO2), a constituent of diesel exhaust fumes. These chlorine detectors were installed by a modification on February 3, 2006, to replace obsolete detectors in the chlorine detection system. This failure mode has the potential to render the CREV system inoperable as a result of EDG operation in response to a Loss of Offsite Power/Loss of Coolant Accident event. As a result of this undocumented and/or unconsidered design input, the modification to replace the obsolete chlorine detectors with detectors of a different design, did not account for the potential impact of NO2. Corrective actions included declaring the CREV system inoperable and removing power from the chlorine detectors to restore the radiation protection mode of the CREV system to an operable status and to revise the design specification for the chlorine detectors to ensure sensitivity to other gases is considered in future designs. The licensee subsequently determined that a suitable replacement for the chlorine detectors could not be obtained and has opted to replace the chlorine injection system with a sodium hypochlorite system as the biocide for plant service water systems. The inspectors reviewed the LER and chlorine detector vendor information and determined that the impact from diesel exhaust on the chlorine detectors was not reasonably within the licensees ability to foresee and, therefore, this issue did not constitute a performance deficiency. The licensee documented the event in AR 202398202398 This LER is closed.

.6 (Closed) LER 05000325,324/2006006: Technical Specifications for Reactor

Recirculation Pump Speed Match Criteria is Non-Conservative.

On October 27, 2006, the licensee concluded that Technical Specification Surveillance Requirement 3.4.1.1, which verifies that recirculation pump speeds are within 20 percent of each other when operating at less than 75 percent of rated core flow or within 10 percent of each other when operating at greater than or equal to 75 percent of rated core flow, did not provide adequate assurance that the recirculation loops are operating within the initial conditions of the design basis LOCA analysis. To be bounded by the analysis, loop flows, vice pump speeds, as a percentage of rated core flow should be within the required percentage limits. This issue was discovered when operators, performing surveillance activities, expressed a concern over the observance of a relatively large difference in measured recirculation loop flows versus associated recirculation pump speeds. The licensee entered the issue into the CAP as ARs 209915 and 210701. The licensee appropriately implemented immediate corrective actions to revise the plant surveillance procedure to ensure plant operation with the design basis LOCA analysis. The licensee submitted a request for license amendment the U.S.

Nuclear Regulatory Commission to correct TS LCO 3.4.1 and TS Surveillance Requirement 3.4.1.1 on December 21, 2006 (BSEP letter 06-0136). The enforcement aspects of this issue are discussed in Section 4OA7. This LER is closed.

.7 (Closed) LER 05000325,324/2007001: E1 to E3 Cross-tie Breaker Unavailable due to

Misalignment.

On January 27, 2007, while performing a breaker alignment surveillance, the licensee identified the Emergency Bus 1 (E1) to E3 cross-tie breaker in an inoperable condition.

Operators found that the breaker was improperly racked-in as indicated by the racking lever being misaligned from the required vertical position and the trip pushbutton being not flush with the breaker cover as required. These indications were due to the breaker being racked-in past the normal connected position which would have prevented closure of the breaker. This breaker is used to cross-tie buses E1 and E3 as necessary to mitigate events (station blackout and certain fires). The licensee entered the issue into the CAP as AR 220519220519 The enforcement aspects of this issue are discussed in Section 4OA7. This LER is closed.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 19, 2007, the resident inspectors presented the inspection results to Mr. Waldrep and other members of his staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

.2 Annual Assessment Meeting Summary/Regulatory Performance Meeting Summary

On April 23, 2007, the NRCs Director of Division of Reactor Projects, Chief of Reactor Projects Branch 4, Region II Public Affairs Officer, and Resident staff assigned to the Brunswick Steam Electric Plant met with Progress Energy - Carolina Power and Light (CP&L) to discuss the NRCs Reactor Oversight Process (ROP) and the Brunswick annual assessment of safety performance for the period of January 1, 2006 - December 31, 2006. In addition, Brunswicks recent performance, including placement of Unit 1 into the degraded cornerstone column of the NRCs Action Matrix was discussed. The major topics addressed were: the NRC s assessment program, the results of the Brunswick assessment, and future NRC inspection activities. Attendees included CP&L management, CP&L site staff, and one member of the public.

This meeting was open to the public. The NRCs presentation material used for the discussion is available from the NRCs document system (ADAMS) as accession number ML071150327. ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

4OA7 Licensee Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for disposition as non-cited violations (NCVs).

• 10CFR50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for structures, systems, and components are correctly translated into specifications, drawings, procedures and instructions. Contrary to the above, initial conditions assumed for the design basis loss of coolant accident analysis were incorrectly translated into Technical Specification 3.4.1, Recirculation Loops operating during conversion to Improved Standard Technical Specification which were implemented in June 1998. This was identified in the licensees CAP as ARs 209915 and 210701. This finding is of very low safety significance because the failure to meet the initial conditions of the loss of coolant accident analysis only potentially affects fuel barrier integrity during loss of coolant accident scenarios.

• 10 CFR Part 20, Appendix G(I)(C)(10), requires licensees to include the identities and activities of individual radionuclides contained in each waste container on the uniform waste manifest (NRC Forms 540 and 541). Contrary to this, on 12/07/05 and 05/09/06, resin liners were shipped to a licensed waste processor and subsequently buried without having a complete list of radionuclides on the waste manifest. Previously, a vendor lab had identified Fe-55 and Pu-239 in the waste stream; however, these radionuclides were not included on the shipping papers/manifest. This issue was identified during a licensee self-assessment and entered into the CAP as ARs 00208924 and 00204387. The finding is of very low safety significance because the error did not cause the waste shipments to be under classified.

• Technical Specification 5.4.1, Administrative Controls (Procedures), requires that written procedures shall be implemented covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33 requires written procedures for the operation of the onsite electrical system. Operating Procedure 1OP-50, Plant Electric System Operating Procedure, Revision 79, contained operating procedures for the onsite electrical system including procedural steps and verifications for racking in 4kV breakers. Contrary to 1OP-50, 4kV breaker E1-E3 Cross-tie Breaker (1-E1-AG0) was not properly racked in following maintenance activities on April 29, 2006. This condition existed until discovered and corrected on January 27, 2007. This issue has been entered into the licensees CAP as AR 220519220519 The regional SRA performed a Phase 3 SDP for the finding using the NRC's risk software. The basic event in the model for the operator action of cross tying the E1 to E3 bus was set to fail. The ability to cross-tie the emergency busses is important to loss of offsite power and loss of electrical bus initiators. Due to the long duration of the finding, it was potentially significant.

However, the final significance of the mis-installed breaker was determined to be Green because of the high likelihood of the operations or maintenance staff recognizing and correcting the problem prior to core damage.

• 10 CFR 50, Appendix B, Criteria III, Design Control, requires, in part, that measures shall be established for the identification and control of design interfaces and for coordination among participating design organizations. These measures shall include the establishment of procedures among participating design organizations for the review, approval, release, distribution, and revision of documents involving design interfaces. Nuclear Generation Group Standard Procedure, EGR-NGGC-0005, Engineering Change, contains the requirements to be followed for the review and approval of design changes. EGR-NGGC-0005, Revision 26, Step 9.3.8, requires the Responsible Engineer to ensure that changes made in response to review comments that may affect other reviewers are communicated to those reviewers. Contrary to the above, the significant changes made to EC 60313 for the new chlorine detectors made during the design review process were not communicated to all reviewers. This finding was greater than minor because it affected the Barrier Integrity Cornerstone objective of maintaining the radiological barrier functionality of control room. A Phase 1 Significance Determination Process review screened the finding as very low safety significance (Green) based on the finding only representing a degradation of the radiological barrier function provided for the control room. The licensee entered the deficiency with the design control process into their corrective action program for resolution (AR 190868190868.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Atkinson, Supervisor - Emergency Preparedness

L. Beller, Superintendent Operations Training

A. Brittain, Manager - Security

T. Cleary, Director - Site Operations

E. ONeill, Manager - Training Manager

J. Fergusen, Manager - ER&C

D. Griffith, Manager - Outage and Scheduling

L. Grzeck, Lead Engineer - Technical Support

E. Harkcom, Service Water System Engineer - BESS

S. Howard, Manager - Operations

R. Ivey, Manager - Site Support Services

J. Johnson, Superintendent - Environmental and Chemistry

S. Larson, NDE Level III ISI Specialist

W. Murray, Licensing Specialist

T. Pearson, Supervisor - Operations Training

A. Pope, Supervisor - Licensing/Regulatory Programs

S. Rogers, Manager - Maintenance

J. Scarola, Site Vice President

T. Sherrill, Engineer - Technical Support

T. Trask, Manager - Engineering

J. Titrington, Manger - Nuclear Assessment Services

M. Turkal, Lead Engineer - Technical Support

J. Vincelli, Supervisor - ALARA

M. Williams, Manager - Operations Support

B. Waldrep, Plant General Manager

B. Wilton, Engineering Supervisor

S. Larson, NDE Level III ISI Specialist

W. Murray, Licensing Specialist

NRC Personnel

Randall

A. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Closed

05000324/2006001 LER Loss of Startup Auxiliary Transformer Results in Unit 2 Manual Reactor Protection System Actuation (Section 4OA3.2)

05000324/2006002 LER Manual Scram Due to Conductivity Increase (Section 4OA3.3)

05000325,324/2006003 LER Control Room Ventilation (CREV) System Inoperable due to Chlorine Detector Modification Deficiency (Section 4OA3.4)

05000325,324/2006005 LER Control Room Emergency Ventilation (CREV) System Inoperable due to Chlorine Detectors (Section 4OA3.5)

05000325,324/2006006 LER Technical Specifications for Reactor Recirculation Pump Speed Match Criteria is Non-Conservative (Section 4OA3.6)

05000325,324/2007001 LER E1 to E3 Cross-tie Breaker Unavailable due to Misalignment (Section 4OA3.7)

Opened and Closed

05000325/2007002-01 NCV Incorrect Fuel Assembly Moved to Core (Section 1R20)