IR 05000324/2004002
| ML041110073 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 04/19/2004 |
| From: | Mccree V Division Reactor Projects II |
| To: | Gannon C Carolina Power & Light Co |
| References | |
| EA-04-076 IR-04-002 | |
| Download: ML041110073 (43) | |
Text
ril 19, 2004
SUBJECT:
BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS. 05000325/2004002 AND 05000324/2004002; PRELIMINARY WHITE FINDING
Dear Mr. Gannon:
On March 20, 2004, the Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Units 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on March 25, April 2, and April 19, 2004, with you 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.
As described in Section 4OA2 of the enclosed report, a finding was identified concerning the failure to take adequate corrective action for conditions adverse to quality associated with the No. 3 emergency diesel generator (EDG 3) jacket water cooling (JWC) system. This corrective action failure resulted in EDG 3 being inoperable for a period greater than the Technical Specifications (TS) allowed outage time. Specifically, excessive leakage occurred from the JWC system during EDG 3 operation from December 8, 2003, until it was corrected on January 7, 2004.
This finding was assessed based on the best available information, including influential assumptions, using the Reactor Safety - Significance Determination Process (SDP) and was preliminarily determined to be a White finding for Unit 2 (i.e., a finding of low-to-moderate safety significance, which may require additional NRC inspection) and a Green finding for Unit 1 (very low safety significance). The difference in risk significance between the units is due to differences in electric bus loads. EDG 3 supplies No. 3 emergency bus with electrical power, which in turn powers a substantial amount of the Unit 2 safety-related loads. However, a lesser amount of Unit 1 loads are powered from emergency bus 3. This finding does not present a current safety concern because several missing jacket water cooling system structural supports
were reinstalled, the system leak was appropriately repaired, and EDG 3 was restored to an operable status on January 7, 2004.
The finding was also determined to involve three violations of NRC requirements. Two apparent violations were identified for Unit 2, involving the failure to take adequate corrective actions in accordance with 10 CFR 50, Appendix B, Criterion XVI, that resulted in the failure to comply with TS 3.8.1. These two apparent violations are being considered for escalated enforcement action in accordance with the General Statement of Policy and Procedure for NRC Enforcement Actions (Enforcement Policy), NUREG-1600. One non-cited violation was identified for Unit 1. Because the finding was determined to be of very low safety significance for Unit 1, and because it is entered into your corrective action program, the NRC is treating this finding as an NCV consistent with Section VI.A of the NRC Enforcement Policy. If you contest the NCV in this report, 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. The current Enforcement Policy is included on the NRCs web site at http://www.nrc.gov/what-we-do/regulatory/enforcement/enforce-pol.html.
Before we make a final decision on this matter, we are providing you an opportunity to (1) present to the NRC your perspectives on the facts and assumptions used by the NRC to arrive at the finding and its significance, and whether you agree with the apparent violations at a Regulatory Conference or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 30 days of the receipt of this letter, and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. If a Regulatory Conference is held, it will be open for public observation. The NRC will also issue a press release to announce the conference. If you decide to submit only a written response, such submittal should be sent to the NRC within 30 days of the receipt of this letter.
Please contact Paul Fredrickson at (404) 562-4530 within 10 business days of the date of your receipt of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination decision and you will be advised by separate correspondence of the results of our deliberations on this matter.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being issued for this inspection finding at this time. In addition, please be advised that the number and characterization of apparent violations described in the enclosed inspection report may change as a result of further NRC review.
CP&L 3 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 by L. Wert for/
Victor M. McCree, Director Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos: DPR-71, DPR-62
Enclosure:
Inspection Report 05000325, 324/2004002 w/Attachments: 1. Supplemental Information, and 2. Significance Determination Process Phase III Summary
REGION II==
Docket Nos: 50-325, 50-324 License Nos: DPR-71, DPR-62 Report Nos: 05000325/2004002 and 05000324/2004002 Licensee: Carolina Power and Light (CP&L)
Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road SE Southport, NC 28461 Dates: December 21, 2004 - March 20, 2004 Inspectors: E. DiPaolo, Senior Resident Inspector J. Austin, Resident Inspector W. Loo, Senior Health Physicist (Sections 2PS, 4OA1 and 4OA5)
R. Hamilton, Health Physicist (Sections 2PS, 4OA1 and 4OA5))
H. Gepford, Health Physicist (Sections 2PS, 4OA1 and 4OA5)
J. Lenahan, Senior Reactor Inspector (Section 1R08)
K. Van Doorn, Senior Reactor Inspector (Section 1R08)
Approved by: Victor M. McCree, Director Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000325/2004002, 05000324/2004002; 12/21/2003 - 03/20/2004; Brunswick Steam Electric
Plant, Units 1 and 2; Problem Identification and Resolution.
The report covered a three-month period of inspection by resident inspectors, regional reactor inspectors, and regional health physics inspectors. One preliminary White finding involved two apparent violations for Unit 2 and one Green non-cited violation (NCV) for Unit 1 were identified. The significance of most findings is indicated by their color (Green, White, Yellow,
Red) using Inspection Manual Chapter (IMC) 609, 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.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
TBD (Unit 2), Green (Unit 1). An inspector-identified finding was identified for the failure to take adequate corrective actions for conditions adverse to quality associated with the No. 3 emergency diesel generator (EDG 3) jacket water cooling (JWC) system. This condition resulted in EDG 3 being inoperable from December 8, 2003, until January 7, 2004, which was contrary to the requirements of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, AC Sources-Operating. Two apparent violations were identified for Unit 2: 10CFR50, Appendix B, Criterion XVI, Corrective Actions; and TS LCO 3.8.1. One non-cited violation was identified for Unit 1: 10CFR50, Appendix B, Criterion XVI.
This finding is greater than minor because it is associated with the availability and reliability of EDG 3 to mitigate events such as a loss of offsite power. The finding was preliminarily determined to have low to moderate safety significance (White) for Unit 2 and determined to have very low safety significance (Green) for Unit 1 because the ability of EDG 3 to mitigate a loss of offsite power event was effected. The difference in risk significance between the units is due to differences in electric bus loads. EDG 3 supplies No. 3 emergency bus with electrical power, which in turn provides a substantial amount of the Unit 2 safety-related loads. However, a lesser amount of load is provided to Unit 1 from emergency bus 3. (Section 4OA2)
Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
Unit 1 began the report period operating at full power. On January 29, 2004, the unit performed an unplanned downpower to approximately 50 percent to facilitate repairs to an electro-hydraulic control fluid leak on the No. 3 main turbine control valve. Also on that date, the unit implemented final feedwater temperature reduction and commenced final coastdown.
Maximum power was restored later that day. On February 29, 2004, Unit 1 performed a plant shutdown to commence refueling outage (RFO B115R1). At the end of the inspection period, refueling operations were complete and the unit was in Mode 4 (cold shutdown).
Unit 2 began the report period operating at full power. On December 31, 2003, an unplanned downpower to approximately 70 percent was performed to facilitate repairs to an electro-hydraulic control fluid leak on No. 4 main turbine control valve. The unit returned to full power on January 1, 2004. On January 17, 2004, the unit performed a planned downpower, to approximately 50 percent, to perform secondary plant maintenance, control rod testing and valve testing. During the subsequent power ascension on January 19, 2004, the unit reduced power to approximately 50 percent in response to abnormal indications (power supply faults) on the A reactor feed pump speed control system. On March 12, 2004, reactor recirculation pump 2A tripped on low lubricating oil pressure, due to a failed open pressure regulating valve, which resulted in an unplanned downpower to approximately 50 percent. Following repairs later that day, the unit returned to maximum power where it remained for the duration of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors assessed the effectiveness of the licensees cold weather protection program as it related to ensuring that the facilitys demineralized water system and condensate storage tank low level switches would remain functional and available in cold weather conditions (1 sample of 2 systems). In addition to reviewing the licensees program-related documents and procedures, walkdowns were conducted of the freeze protection equipment (e.g., heat tracing, area space heater, etc.) associated with the above systems/components. Licensee problem identification and resolution were also addressed. This included a review of Action Request (AR) 116118, which documented that the Unit 1 condensate storage tank (CST) level instrumentation had been agitated during cold weather monitoring. This caused the reactor core isolation cooling (RCIC)system suction to automatically transfer from the CST to the suppression pool.
Documents reviewed are listed in Attachment 1.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
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 following system restoration after maintenance.
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. Administrative Procedure ADM-NGGC-0106, Configuration Management Program Implementation, was reviewed by the inspectors to verify that available structures, systems or components (SSCs) met the requirements of the licensees configuration control program. Documents reviewed are listed in Attachment 1.
- Unit 2 B loop of residual heat removal when A loop was OOS January 28-29, 2004
- Unit 1 residual heat removal while on shutdown cooling following system restoration on March 12, 2004
- Unit 1 supplemental spent fuel pool cooling system when residual heat removal-shutdown cooling system was OOS on March 13, 2004
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors reviewed current ARs and work orders (WOs) associated with the fire suppression system to confirm that their disposition was in accordance with OAP-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 below listed 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. The inspectors reviewed Prefire Plan 0PFP-DG, Diesel Generator Building Prefire Plans (Rev. 8) to determine correct configuration:
- Switchgear rooms E1, E2, E3 and E4 in Diesel Generator Building, 50' elevation (4 areas)
- Switchgear rooms E5, E6, E7 and E8 in Diesel Generator Building, 23' elevation (4 areas)
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities
a. Inspection Scope
Inservice Inspection (ISI)
The inspectors reviewed ISI procedures, observed in-process ISI work activities, 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 portions of ultrasonic (UT) examinations performed on four welds to verify the exams were being performed in accordance with the ASME Boiler and Pressure Vessel Code,Section XI, Appendix VIII, 1995 Edition including 1996 Addenda as modified by the Performance Demonstration Initiative (PDI) Program. The exams included an austenitic weld, a ferritic weld, a reactor pressure vessel weld, and a nozzle inner corner radius area. The inspectors also observed the UT exam of a dissimilar metal weld, which was conducted based on a recent industry leak discovered on a nozzle weld with a similar configuration and composition. These inspections included welds 1B32RECIRC-4-A-2, 1E213-1-3-SWA, 1B11-RPV-N9, and 1B11N9-RPV-FW1CRD274 and nozzle 1B11-RPV-N4B-IRS.
The inspectors reviewed non-destructive examination (NDE) reports for visual (VT-3)inspection of 60 hydraulic snubbers and functional testing of five snubbers performed during the current outage. Qualification and certification records for examiners, and equipment for selected examination activities were reviewed. In addition, the inspectors examined snubbers on pipe supports during a walkdown of the Unit 1 drywell.
Examination of the snubbers included attachment to supporting structures and piping, fluid levels in reservoirs, absence of fluid leakage from the snubbers, and overall condition of the snubbers. A sample of ISI issues in the licensees corrective action program were reviewed for adequacy. The inspectors also reviewed the results of a self-assessment of the snubber inspection program completed in November, 2002 and the associated corrective actions to address three assessment findings. Documents reviewed are listed in Attachment 1.
The inspectors reviewed records for the following Code repairs:
- WO 525425, Repair of Through Wall Leak on 1-SW-103-24-157
- WO 031176, Replacement of SLC Flexhoses IWE Containment Vessel Inspection The inspectors reviewed the licensees ISI procedures for the containment (drywell and torus) inspection to determine if the procedures complied with the TS, ASME Boiler and Pressure Vessel Code, Article IWE of Section XI, 1992 Edition and 1992 Addenda, and 10 CFR 50.55a. The inspectors also reviewed records documenting visual inspections performed on the containment during the current outage and during the March, 2002 refueling outage to determine if the licensee program for inspection of the containment was being performed in accordance with the requirements specified in Article IWE of Section XI, 1992 Edition and 1992 Addenda, and 10 CFR 50.55a. The inspectors examined the interior surfaces of the Unit 1 containment liner and the moisture barrier at the intersection of the liner and interior concrete floor area. Documents reviewed are listed in Attachment 1.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
Quarterly Review The inspectors observed licensed operator performance and reviewed the associated training documents during simulator training sessions for Cycle 2004-01. The simulator observation and review included an evaluation of alarm response procedure utilization.
The inspectors reviewed Procedure OTPP-200, Licensed Operator Continuing Training (LOCT) Program, to verify that the program ensures safe power plant operation. The simulator training observed tested the operators ability to perform a reactor startup.
The inspectors reviewed the operators activities to verify consistent clarity and formality of communication, conservative decision-making by the crew, and appropriate use of procedures. Group dynamics and supervisory oversight, including the ability to properly identify and implement appropriate TS actions, regulatory reports, reactivity management, and the use of peer checking, were observed. The inspectors assessed whether appropriate feedback was planned to be provided to the licensed operators.
The inspectors reviewed documents listed in Attachment 1.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
For the equipment issues described in 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 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-NGG-0101, Maintenance Rule Program. The inspectors also reviewed deficiencies related to the work activities listed below to verify that the licensee had identified and resolved deficiencies in accordance with Procedure CAP-NGGC-0200, Corrective Action.
- AR 105773, Unit 2 B core spray pump inoperability due to room fan breaker failure
- AR 114950, emergency core cooling system cabinet 2-XU-63 inadvertently de-energized during maintenance To assess the licensees identification and resolution of problems, the inspectors reviewed AR 116354 which documented that the time to repair a Unit 2 core spray room fan breaker was not counted toward core spray system unavailabilty.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
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 OAP-025, BNP Integrated Scheduling and Technical Requirements Manual (TRM)5.5.13, Configuration Risk Management Program. The inspectors reviewed the effectiveness of risk assessments performed prior to changes in plant configuration for maintenance activities (planned and emergent). The review was conducted to verify that, upon unforseen 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 WOs for the following OOS equipment or conditions, and the documents listed in Attachment 1:
- AR 116796, Unit 1 electro-hydraulic leak on main turbine control valve #3 and subsequent downpower to facilitate repairs (emergent)
- AR 116670, vital battery chargers susceptible to tripping during motor starts with the batteries disconnected from the DC switchboards (emergent)
- AR 116109, EDG #1 inoperable due to cracked casing on auxiliary lubricating oil pump (emergent)
- AR 121226, Unit 2 A recirculation pump motor-generator trip on low lubricating oil pressure resulting in single loop operation (emergent)
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Non-Routine Plant Evolutions and Events
a. Inspection Scope
The inspectors reviewed or observed the operating crews performance during the following transients and abnormal conditions to verify the response was in accordance with procedures and training. Operator logs, plant computer data, and associated operator actions were reviewed. Documents reviewed are listed in Attachment 1.
- Unit 2 downpower to repair electro-hydraulic control leak on main turbine control valve on December 31, 2003
- Unit 2 entry into Abnormal Operating Procedure 0AOP29, Malfunction of Annunciators (Rev. 7), due to loss of control room annunciator Panel P603 on February 12, 2004
- Unit 2 downpower due to A recirculation pump trip on March 12, 2004
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the operability evaluations associated with the following five issues, 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) the adequacy of any compensatory measures in place, including their intended use and control; and 4) where continued operability was considered unjustified, the impact on TS LCOs 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 114576, EDG 3 past operability determination
- AR 114454, through-wall leak discovered on the conventional service water discharge header in the Unit 2 reactor building
- AR 120719, Vital Battery 1-1B terminal connections not torqued to vendor-recommended value due to out-of-tolerance maintenance and test equipment
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
For the post-maintenance tests and maintenance activities listed below, the inspectors reviewed the 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, and 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. Documents reviewed are listed in Attachment 1.
- WO 431339, Unit 2 high pressure coolant injection system electric governor capacitor removal
- WO 526183, repair Unit 1 A core spray pump breaker relay logic following delayed trip during 0MST-DG11R
- WO 224628, retorque Vital Battery 1B-1 terminal connections following discovery of out-of-tolerance torque wrench
- WO 289505, disassemble, inspect, and repair Unit 1 reactor-building-to-suppression-chamber vacuum breaker (1-CAC-X20A/B)
To assess the licensees identification and resolution of problems, the inspectors reviewed AR 121303. The AR addressed an inspector-identified issue regarding additional post-maintenance testing requirements added after initial planning of work associated with torquing of vital battery terminal connections.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors evaluated Unit 1 RFO B115R1 activities which commenced on February 28, 2004. At the completion of the inspection, fuel movement was complete and the unit was in Mode 4 (cold shutdown) and preparing for startup activities. Documents reviewed are listed in Attachment 1. The following specific areas were reviewed:
Outage Plan. The inspectors reviewed Brunswick Nuclear Plant Unit 1 Safe Shutdown Risk Assessment, for RFO B115R1. 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 was also to verify that, for identified high risk significant conditions, contingency measures were identified and incorporated into the risk plan, and that defense-in-depth was maximized to the extent possible. The inspectors frequently monitored the risk condition during the outage.
Shutdown and Cooldown. The inspectors observed portions of the Unit 1 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 1PT-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 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, reactor cavity, and spent fuel pool 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 and to confirm that no work was ongoing that might prevent system use for decay heat removal. The inspectors conducted a review of the higher outage risk conditions including the periods of EDG load testing and natural circulation flow to both loops of shutdown cooling being secured for maintenance. 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. Licensee performance was compared to Procedure 0AP-038, Reactivity Management Program Manual.
- Inventory Control. 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.
- 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 reviewed the following issues identified during the outage to verify that the appropriate corrective actions were implemented:
- AR 121592, Drywell liner indications missed during initial inspection of H Downcomer
- AR 121137, Incorrect rotation of supplemental spent fuel pool cooling system cooling tower fans
- AR 119714, Potential overthrust/overtorque of residual heat removal system Suppression Pool Suction Valves (1-E11-F004B/D)
- AR 120388, Valve actuator motor removed from Valve 1-B32-F031A vice 1-B32-F031B (recirculation pump discharge valves)
- AR 120524, Foreign material found in drywell-to-torus vent lines
- AR 119921, Loss of control room reactor vessel level indication while in Mode 5 (refueling)
- AR 121061, Higher than expected heatup of spent fuel pool/reactor cavity while removing decay heat using supplemental spent fuel pool cooling system
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
Routine Surveillance Testing The inspectors either observed surveillance tests or reviewed test data for the risk significant SSC surveillances, listed below, to verify the tests met TS surveillance requirements, Updated Final Safety Analysis Report commitments, 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. The inspectors reviewed the following documents as well as documents listed in Attachment 1:
- Periodic Test 0PT-12.2C, No. 3 Diesel Generator Monthly Load Test (Rev. 77)
- Maintenance Surveillance Test 0MST-DG-11R, DG-1 Loading Test (Rev. 1)
- Operating Instruction 0OI-03.6, Radioactive Waste Operator Daily Surveillance Report (Rev. 19)
- Containment isolation valve local leak rate testing, Periodic Test 0PT-20.3a.1, B21-F022A and B21-F028A (A main steam isolation valves) Leak Test (Rev. 10)
Inservice Surveillance Testing (IST)
The inspectors reviewed the performance of Maintenance Surveillance Test 0MST-CAC501R, CAC Reactor Building to Suppression Chamber Vacuum Breaker Channel Calibration (Rev. 2) performed on Unit 1. 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
2OS1 Access Control To Radiologically Significant Areas
a. Inspection Scope
Access Controls The inspection reviewed the licensees program activities for monitoring workers and controlling access to radiologically significant areas and tasks. The inspectors evaluated procedural guidance, directly observed implementation of administrative and established physical controls, assessed worker exposures to radiation and radioactive material, and appraised radiation worker and technician knowledge of, and proficiency in, implementing Radiation Protection (RP) program activities.
During the onsite inspection, radiological controls for maintenance activities were observed and discussed with cognizant licensee representatives. The inspectors observed work associated with new fuel receipt, shielding of a residual heat removal (RHR) heat exchanger, and movement of an empty spent fuel shipping cask into the reactor building. In addition, the inspectors independently measured radiation dose rates and evaluated the established postings. Radiological postings, labeling and access controls were directly observed by the inspectors during tours of the Unit 1 and Unit 2 reactor buildings, lower elevations of the turbine building and radioactive waste (radwaste) processing areas. Control of locked high radiation area (LHRA) keys and the physical status of LHRA doors were also independently evaluated by the inspectors.
Occupational workers adherence to selected radiation work permits (RWPs) and health physics technician (HPT) proficiency in providing job coverage were evaluated by the inspectors through direct observations, review of selected exposure records and investigations, and interviews with cognizant licensee representatives. Occupational exposure data associated with direct radiation, potential radioactive material intakes, and discrete radioactive particle or dispersed skin contamination events were reviewed and assessed independently by the inspectors.
RP program activities were evaluated against 10 CFR Part 19.12; 10 CFR Part 20, Subparts B, C, F, G, H, and J; UFSAR details in Section No. 11, Radioactive Waste Management, and Section No. 12, Radiation Protection; TS Sections 5.4.1, Procedures, and 5.7, High Radiation Area (HRA); and approved licensee procedures. Licensee guidance documents, records, and data reviewed within this inspection area are listed in Attachment 1.
Problem Identification and Resolution Corrective Action Program (CAP) documents associated with radiological controls, personnel monitoring, and exposure assessments were reviewed and discussed with cognizant licensee representatives. The inspectors assessed the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with Nuclear Generation Group Common Procedure CAP-NGGC-0200, Corrective Action Program, Revision (Rev.) 9. Specific condition report (CR) documents that were reviewed and evaluated in detail for these program areas are identified in Attachment 1.
b. Findings
No findings of significance were identified.
2OS3 Radiation Monitoring Instrumentation and Protective Equipment
a. Inspection Scope
Radiation Monitors and Protective Equipment The inspectors reviewed the operability and maintenance of selected radiation detection and respiratory protective equipment. The inspection consisted of document review, discussions with plant personnel, and observation of routine testing for the following items: area radiation monitors (ARMs), continuous air monitors (CAMs), personnel monitors, portable detection instruments, and self-contained breathing apparatus (SCBA) units.
The inspectors reviewed calibration records for selected ARMs and CAMs and HPTs regarding the results. The placement and use of CAMs inside containment during the previous Unit 1 refueling outage was evaluated and discussed with cognizant licensee representatives.
Whole body counter (WBC) calibration records and daily source check trends were reviewed by the inspectors and discussed with dosimetry personnel. Intakes of radioactive material by individuals for 2003 were also reviewed by the inspectors and discussed with cognizant dosimetry personnel.
Procedural guidance for the use and calibration of portable survey instruments was evaluated by the inspectors. The inspectors observed the daily source check of an RO-20 and a Teletector survey meter and compared the results to specified tolerances.
The inspectors interviewed cognizant licensee representatives regarding the licensees program for the use of electronic dosimeters (including use in high noise areas) and observed the functional test and calibration of an alarming dosimeter. In addition, calibration records were reviewed for a Teletector, RO-2, RO-20, and RM-14 survey instruments and a SAM No. 9 article monitor in use at the time of the inspection.
The licensees respiratory protection program guidance and its implementation for SCBA use were evaluated by the inspectors and discussed with cognizant licensee representatives. The number of available SCBA units and their general material and operating condition were observed during tours of the control room and reactor auxiliary building. Current records associated with supplied air quality for staged SCBA equipment were evaluated by the inspectors. In addition, the inspectors interviewed control room operators to determine their level of knowledge of available SCBA equipment storage locations and availability of prescription lens inserts, if required.
Procedures and training for performing a SCBA bottle change - out were also reviewed by the inspectors.
Program guidance, performance activities, and equipment material condition were reviewed against details documented in 10 CFR Parts 20 and 50; UFSAR Section 12.1.4, Area Monitoring; applicable sections of NUREG-0737, Clarification of Three Mile Island (TMI) Action Plan Requirements, November 1980; Regulatory Guide (RG) 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Rev. 3; RG 8.15, Acceptable Programs for Respiratory Protection, Rev. 1; and applicable licensee procedures. All documents reviewed are listed in Attachment 1.
Problem Identification and Resolution Selected CRs associated with area radiation monitoring equipment, portable radiation detection instrumentation, and respiratory protective program activities were reviewed and assessed. The inspectors also assessed the licensees ability to characterize, prioritize, and resolve the identified issues in accordance with Procedure CAP-NGGC-0200, Corrective Action Program, Rev. 9.
b. Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
a. Inspection Scope
Effluent Processing Equipment The inspectors reviewed and evaluated the operability, availability and reliability of selected radioactive effluent process sampling and detection equipment used for routine and accident monitoring activities. Inspection activities consisted of direct observation of installed equipment configuration and operation and review of calibration and performance data for the liquid and gaseous effluent process systems.
The inspectors directly observed Unit 1 and Unit 2 equipment material condition and assessed selected gaseous and liquid effluent processing and monitoring components against design configuration and operating specifications. During walk-downs, accessible sections of the liquid waste system, including waste monitor tanks, system piping, and radioactive waste liquid effluent monitor equipment were assessed for material condition and conformance with current system design diagrams. Inspected components of the main gaseous effluent process and release system included the parts of the plant vent radiation monitoring system along with associated sample lines.
The inspectors interviewed cognizant chemistry supervision and system engineering personnel regarding liquid and gaseous radwaste system configurations, system reliability, system modifications, and effluent monitor operation.
The inspectors reviewed applicable sections of effluent monitor calibration procedures and evaluated results of calibration and/or functional tests for the radwaste liquid effluent monitor and its associated flow monitor, the main stack radiation monitor, the reactor building roof vent samplers, the turbine building vent monitor, the process gas (noble gas) effluent monitor and high efficiency particulate (HEPA) filter systems.
Reviewed data included isotopic calibration records, source check results, flowmeter calibration records, and HEPA surveillance records. The inspectors also reviewed OOS data and contingency sampling records for selected effluent monitors for the period of November 2002 - October 2003.
Installed configuration, material condition, operability, and reliability for selected effluent sampling and monitoring equipment were reviewed by the inspectors against details documented in the following: 10 CFR Part 20; RG 1.33, Quality Assurance Program Requirements (Operation), February 1978; RG 1.21, Measuring, Evaluating and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-Water Cooled Nuclear Power Plant, June 1974; ANSI-N13.1-1969, Guide to Sampling Airborne Radioactive Materials in Nuclear Facilities; ANSI-N13.10-1974, ANS Specification and Performance of On-Site Instrumentation for Continuously Monitoring Radioactivity in Effluents; TS Section 5.6.3; the Offsite Dose Calculation Manual (ODCM), Rev. 26; and UFSAR Chapters 9 and 11.
Procedures and records reviewed during the inspection are listed in Attachment 1.
Effluent Release Processing and Quality Control Activities The inspectors evaluated the licensees performance in conducting effluent release processing and quality control (QC) activities including implementation of program guidance and chemistry staff proficiency. The inspection consisted of interviews of cognizant chemistry staff and supervision and observation of a chemistry staff member demonstrating the normal processing of routine release logging/permitting. The review included release documentation and applicable licensee procedures.
The effluent release program was evaluated against the following guidance: 10 CFR Part 20 and Appendix I to 10 CFR Part 50; ODCM; RG 1.21, RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment, December 1977; and RG 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50 Appendix I, October 1977. Procedures and records reviewed during the inspection are listed in Attachment 1.
Problem Identification and Resolution Two licensee CRs and one audit associated with effluent release activities were reviewed and assessed. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with Nuclear Generation Group Common Corrective Action Procedure CAP-NGGC-0200, Corrective Action Program, Rev. 9. Documents reviewed are listed in Attachment 1.
b. Findings
No findings of significance were identified.
2PS3 Radiological Environmental Monitoring Program (REMP) and Radioactive Material Control Program
a. Inspection Scope
REMP Implementation The inspectors reviewed and discussed with cognizant licensee representatives the results published in the Brunswick Annual Radiological Environmental Operating report for CY 2002. The inspectors observed the collection and preparation of weekly particulate and radioiodine samples by licensee personnel and assessed material condition of three air sampling stations (Station Nos. 201, 202, 203), one river water sampling station (Station No. 400), one vegetation sampling station (Station No. 800),and six thermoluminescent dosimeters (TLDs) (Station Nos. 5, 8, 14, 24, 25, 81) to evaluate procedural compliance. The inspectors assessed the calibration status of each air sampling pump. The inspectors also evaluated the placement of collection station locations against the sectors specified in the ODCM using the NRC global positioning system. The inspectors observed and discussed with cognizant licensee representatives the procedures, methods, and equipment used to perform vegetation, sediment, and fish/invertebrate sampling. The inspectors reviewed and discussed with cognizant licensee representatives the procedures used to calibrate and determine the L LD for environmental sample gamma spectroscopy analysis.
REMP guidance, implementation, and results were reviewed against ODCM guidance and applicable procedures listed in Attachment 1.
Meteorological Monitoring Program The inspectors reviewed the operability of the meteorological monitoring equipment and operator access to meteorological data. Current meteorological monitoring equipment performance and calibration were reviewed with the system engineer. Licensee technicians primarily responsible for equipment maintenance and surveillance were interviewed by the inspectors concerning equipment performance, reliability, and routine inspections. Inspectors compared the meteorological data available in the control room against the meteorological data recorder at the tower location.
Meteorological instrument operation, calibration, and maintenance were reviewed against UFSAR, Chapter 2; NRC Safety Guide 23, Onsite Meteorological Programs-1972; and applicable licensee procedures. Documents reviewed are listed in
1. Unrestricted Release of Materials from the Radiologically Controlled Area (RCA)
The inspectors reviewed calibration records for two personnel contamination monitors and one material release monitor. The inspectors also observed source checking of three material survey monitors. Types of sources used for checks and minimum detectable activities were discussed with an instrument technician.
The inspectors verified that radiation detection sensitivities were consistent with NRC guidance in IE Circular 81-07 and IE Information Notice 85-92. Documents reviewed are listed in Attachment 1.
Problem Identification and Resolution Licensee CAP issues associated with environmental monitoring, meteorological monitoring, and release of materials were reviewed and discussed with cognizant licensee representatives. The inspectors assessed the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with Procedure CAP-NGGC-0200, Corrective Action Program, Revision 9. Specific documents that were reviewed and evaluated in detail for these program areas are identified in
1.
b. Findings
No findings of significance were identified.
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors sampled licensee submittals for the Unit 1 and 2 performance indicators (PIs) listed below. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, were used to confirm the reporting basis for each data element.
Reactor Safety Cornerstone
- Unplanned Scrams per 7000 Critical Hours
- Scrams with Loss of Normal Heat Removal
- Emergency AC Power-Safety System Unavailability A sample of plant records and data was reviewed for the period April 2003 through December 2003, and compared to the reported data to verify the accuracy of the PIs.
This included operating logs and licensee event reports. The licensees corrective action program records were also reviewed to determine if any problems with the collection of PI data had occurred.
Occupational Radiation Safety Cornerstone
- Occupational Exposure Control Effectiveness The inspectors reviewed CR records for HRAs, very high radiation areas (VHRA), and unplanned exposure occurrences for the period of December 2002 through December 2003, to verify that TS and 10 CFR 20 non-conformances were properly classified as PIs. The inspectors also reviewed radiological controlled area exit transactions with exposures greater than 100 millirem (mrem) and investigated a sample of those transactions to determine whether they were within the respective RWP and to verify that those greater than 100 mrem unplanned exposure were entered in the corrective action program and listed as a PI. Reviewed documents are listed in Attachment 1.
Public Radiation Safety Cornerstone
- RETS/ODCM Radiological Effluent Occurrences The inspectors reviewed radiological control effluent release occurrences for the from January 2002 through December 2003. For the period, the inspectors reviewed data reported to the NRC, procedural guidance for reporting PI information, and two CRs listed in Attachment 1. In addition, the inspectors reviewed monthly PI reports from January 2002 through December 2003.
b. Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
a. Inspection Scope
While performing a plant status review on January 5, 2004, the inspectors noted that during the monthly performance of an EDG 3 surveillance, an operability determination was made relative to an identified jacket cooling water (JWC) system leak. Subsequent to the EDG run, the EDG was considered inoperable. The licensee determined that a leak had also existed during the same surveillance in December 2003, with corrective action repair being performed shortly after the leak was identified. However, after the January 2004 leak was noted, further review identified that the corrective action repair in December 2003 did not fix the leak, leading directly to the problem in January 2004.
Because of the potential significance of the corrective action problem from the December 2003 repair, the inspectors selected AR 114576, DG3 Past Operability Determination, for detailed review. The review was performed to verify that conditions adverse to quality were addressed in a manner that was commensurate with the safety significance of the issue. Additional documents reviewed are listed in Attachment 1.
b. Findings
Introduction.
A preliminary White finding with two apparent violations was identified for Unit 2, and one Green NCV was identified for Unit 1, associated with the failure to take adequate corrective actions on the EDG 3 JWC system leak.
Description.
During the monthly (surveillance) testing of EDG 3 on December 7, 2003, a 0.5 gallons per minute (gpm) leak on the JWC system was noted on engine start-up.
The leak later decreased to approximately 40 drops per minute following system heat-up to normal operating temperature. At that time, Operations, with Engineerings recommendation, determined the EDG was operable based on the low operating leak rate and the fact that makeup was available using water supplied (hard piped) from the demineralized water system. On December 8, 2003, a maintenance mechanic tightened the pipe coupling to the vendor recommended torque value using the minor maintenance work process. However, a post-maintenance functional test to verify that the leak had stopped, was not performed.
On January 4, 2004, during monthly testing of EDG 3, a 1 gpm leak was observed on the JWC system from the same coupling. In consultation with the system engineer, Operations initially determined EDG 3 was operable for the same reasons used in the December 7, 2003 leakage event. That is, the decision was based on the ability to make up to the JWC system expansion tank from the sites demineralized water system.
After a management review with respect to the impact of the leak size on the operability decision, Operations reevaluated the ability (and timeliness) to make up the water to the EDG. Subsequently, Operations determined the leak size was too large for timely makeup and declared the EDG inoperable.
Repairs were initiated and, following the repair activities, EDG 3 was restored to an operable status on January 7, 2004. The inspectors challenged the appropriateness of considering the EDG operable on December 7, 2003, based on both the leak size and the availability of the demineralized water system, since the system would not be available during an event for which the EDG would be called upon to function. The demineralized water system is not safety-related (i.e., not seismically qualified) or backed up by emergency power. Proper operation of this system relies on pumps that lose power upon a loss of off-site power. The unavailability of the demineralized water system was not considered during either operability evaluation. Additionally, the inspector noted that the JWC expansion tank low level alarm was out-of-service during the time period in question which could have complicated operator diagnosis/response to the leak.
The licensee entered the issue into the corrective action program as ARs 114576 and 114573. The cause of the condition was attributed to missing pipe supports which resulted in an inadequate pipe coupling alignment. The missing supports factor was considered an historical condition and, as such, the licensee did not pursue the cause of that condition, or the period of time the supports were missing. The licensee determined that an adequate functional test following the maintenance performed on December 8, 2003, would have been a leak check of the system at normal operating pressure.
However, this test was not performed. The licensee concluded that the maintenance performed on December 8, 2003, had most likely aggravated the coupling leak.
Accordingly, the licensee determined that the EDG had been inoperable since December 8, 2003, a significantly longer time than the seven days of allowed outage time in TS 3.8.1.
Timely and appropriate corrective action, commensurate with the potential safety significance, was not taken for leakage identified from EDG 3 jacket water cooling system on December 7, 2003. Missing pipe supports on the jacket water cooling system resulted in misalignment of a system pipe coupling which caused system leakage. Maintenance practices and controls for repairs performed on December 8, 2003 to correct the deficiency caused the leakage to increase which was not detected due to the failure to perform appropriate post-maintenance testing. Operability assessments of system leakage, on both December 7, 2003, and on January 4, 2004, did not consider the potential impact of a loss of off-site power on the ability of the demineralized water system to make up to the EDG to compensate for the degraded condition (inspector identified). This performance deficiency resulted in Units 1 and 2 not meeting TS Limiting Condition of Operation 3.8.1, AC Sources-Operating.
Analysis.
The finding affects the Mitigating System Cornerstone for Units 1 and 2. The finding is more than minor because it is associated with the availability and reliability of EDG 3 to mitigate events such as a loss of offsite power. Because this finding represented an actual loss of safety function of EDG 3 for greater than the TS LCO 3.8.1 allowed outage time for one EDG (i.e., seven days), an SDP Phase II analysis was performed. The dominant core damage sequence was Loss of Offsite Power (LOOP)and LOOP with Loss of One AC Division. The results of the Phase II analysis required a Phase III evaluation.
A phase 3 analysis was performed using the Brunswick SPAR model. Assumptions critical to this evaluation involved the ability of operators to maintain jacket water level by making up to the leaking system. This analysis assumed that for a period of 26 days, EDG 3 could have been recovered by an operator refilling the jacket water cooling system. For a 37.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period when the demineralized water tank level was too low to support gravity feed the EDG was unavailable with no recovery. The EDG was also unavailable due to repair of the performance deficiency for a period of 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br />. The probability of the operator failing to recover the EDG was estimated at 0.1 using SPAR human reliability analysis (HRA) methods. The SPAR analysis identified the loss of offsite power with failures to supply power to the emergency busses as dominant risk sequences. Because some of the sequences also involve failures to depressurize the reactor, the analysis of large early release frequency (LERF) was also an important consideration. However, based on the unique containment structure of Brunswick, LERF was determined to not be a significant factor for the loss of power sequences.
External events were considered but also determined not to be significant contributors to this evaluation because their initiating event frequencies were small compared to the loss of offsite power frequency. The SPAR model result for the change in core damage frequency (CDF) was 1.1e-6.
The finding represented low to moderate safety significance and was determined to be preliminarily White on Unit 2 based on CDF and LERF. The finding was determined to be Green on Unit 1 based on CDF and LERF. The difference between the two units is primarily because EDG 3 is a primary EDG for Unit 2 and a backup EDG for Unit
1. See Attachment 2, Significance Determination Process Phase III Summary, for
further details.
Enforcement.
10 CFR 50, Appendix B, Criteria XVI, requires in part that measures shall be established to assure that conditions adverse to quality, such as failures and malfunctions, are promptly identified and corrected.
Technical Specification (TS) Limiting Condition of Operation 3.8.1, AC Sources-Operating, requires four EDGs to be operable when in Mode 1 with operation with three EDGs allowed for a period of seven days.
Contrary to the above, two structural supports located on the jacket water turbo charger supply line for EDG 3 were removed prior to approximately January 1, 2001 and were not reinstalled until January 7, 2004. These supports are documented in Brunswick as-built Drawing No. FP-20323, Rev K, dated 6/16/03. This failure to reinstall the missing supports, a condition adverse to quality, resulted in an inadequate pipe coupling, which contributed to a jacket water system leak on December 7, 2003. A jacket water system leak on EDG 3, a condition adverse to quality, identified on December 7, 2003, was not promptly corrected. Maintenance performed on December 8, 2003, did not correct the deficiency, so that the leak was still present and larger on January 4, 2004. As a result, only three EDGs were operable from December 8, 2003 until January 7, 2004, while Units 1 and 2 were in Mode 1 and the licensee did not satisfy the requirements of TS LCO 3.8.1, AC Sources-Operating.
This finding does not present a current safety concern because the jacket water cooling system structural supports were reinstalled, the system leak was appropriately repaired, and EDG 3 was restored to an operable status on January 7, 2004. Planned corrective actions include actions to reinforce minor maintenance and functional verification requirements and communicating expectations to maintenance personnel. This issue has been entered into the corrective action program as ARs 114573 and 114576. The licensee documented the failure to meet TS LCO 3.8.1 in Licensee Event Report 05000325,324/2004-001-00, Emergency Diesel Generator No. 3 Condition Prohibited by the Technical Specifications, dated March 4, 2004. These NRC-identified apparent violations (AVs) of regulatory requirements are identified for Unit 2 as AV 05000324/2004002-01, Inadequate Corrective Actions for EDG Jacket Water Cooling Leak, and AV 05000324/2004002-02, Failure to Meet TS LCO 3.8.1.
Because the failure to promptly correct the jacket water cooling system leak is of very low safety significance for Unit 1 and has been entered into the corrective action program, this finding is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000325/2004002-03, Inadequate Corrective Actions for EDG Jacket Water Cooling Leak Results in Failure to Meet TS LCO 3.8.1.
4OA3 Event Follow-up
a. Inspection Scope
The inspectors reviewed the licensees 10 CFR 50.73 telephone notification as a result of receiving an invalid primary containment isolation system Group 6 actuation on January 11, 2004. The isolation was caused by the reactor building exhaust radiation monitor (1-D12-RM-K609B) input signal spiking. All required actuations operated properly (i.e. secondary containment isolation, standby gas treatment system automatic start, etc.). The cause of the invalid actuation was determined to be a failed detector due to end-of-life. The inspectors reviewed the 10 CFR 50.73 notification to assess appropriate reporting within established criteria.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
.1 Spent Fuel Material Control and Accounting
a. Inspection Scope
The inspectors completed Phase I and Phase II of Temporary Instruction 2515/154, Spent Fuel Material Control and Accounting at Nuclear Power Plants.
b. Findings
No findings of significance were identified.
.2 Review of 2003 World Association of Nuclear Operators (WANO) Final Report
The inspectors reviewed the 2003 WANO Peer Review, Final Report, for the Brunswick Steam Electric Plant, dated March 15, 2004. The review determined that the results of the WANO report were generally consistent with the results of similar evaluations conducted by the NRC. The inspectors concluded that no additional Regional follow-up concerning this report was warranted.
.3 (Closed) Unresolved Item (URI)05000324/2003006-02, Unit 2 Reactor Feed Pump
Speed Control Modification This item was opened for a finding involving an inadequate design modification of the Unit 2 reactor feed pump speed control system. The issue was unresolved pending significance determination. The NRC preliminarily determined the issue to be of low to moderate (White) risk significance as discussed in an NRC letter dated January 30, 2004. The licensee provided additional risk information in a Regulatory Conference on March 17, 2004. Following review and consideration of the information provided, the issue was determined to be of very low risk significance (Green). The final risk significance determination was documented in NRC Inspection Report 50-325/2004-007 dated April 2, 2004. This URI is closed.
.4 (Closed) URI 50000325, 324/2002003-02: Failure of SCBA Training Program to Include
Demonstration of Proficiency in SCBA Cylinder Change-out In September 2002, the inspectors determined that Lesson Plan GN6C10G for non-fire brigade workers did not require instruction for SCBA qualified personnel on how to replace air supply bottles nor require them to demonstrate their ability to do so.
The inspectors reviewed the licensees followup to this URI by reviewing the actions taken by the licensee in response to AR 00067106, Training for SCBA Bottle Changeout, dated July 25, 2002. Based on a review of the actions taken by the licensee and discussions with cognizant licensee representatives, the inspectors determined that the licensee had revised applicable procedures to incorporate and formalize the process for health physics technician support for SCBA cylinder bottle change outs. In addition, the training was revised to include practicals for individuals to specifically demonstrate the proper bottle changeout procedure with the instructor present. The inspectors interviewed several individuals from the Maintenance and Radiation Protection Departments about SCBA bottle changeout and each individual was able to satisfactorily describe the process. In reviewing the historical significance of this issue, the inspectors noted that health physics staff had been trained on bottle changeout (as part of their fire brigade responsibility). They had been previously utilized as standby rescue personnel to aid individuals who would have required bottle changeout or who were experiencing trouble extricating themselves. However, this process had not been proceduralized. Also, an assigned loss prevention unit auxiliary operator for each shift had also been previous trained in the changeout process. As such, this finding was determined to be a violation of 10 CFR 20.1703(c), but of minor significance and, thus, is not subject to enforcement action in accordance with section IV of the NRC Enforcement policy. Reviewed documents are listed in Attachment 1.
This URI is closed.
4OA6 Meetings, Including Exit
On March 25, 2004, the resident inspectors presented the inspection results to Mr. C. J. Gannon and other members of his staff. Additional discussions further clarifying the findings of this report were held on April 2 and 19, 2004. The inspectors confirmed that proprietary information was not provided or examined during the inspection.
ATTACHMENTS 1.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- G. Atkinson, Supervisor - Emergency Preparedness
- L. Beller, Supervisor - Licensing/Regulatory Programs
- H. Bordeaux, QC Manager
- A. Brittain, Manager - Security
- E. Conway, Senior Nuclear Security Specialist
- D. DiCello, Manager - Nuclear Assessment
- C. Elberfeld, Lead Engineer - Technical Support
- J. Frisco, Superintendent-Mechanical Maintenance
- C. Gannon, Site Vice President
- J. Gawron, Training Manager
- M. Grantham, Superintendent-Design Engineering
- S. Hamilton, Envirnonmental and Radiation Control Manager
- D. Hinds, Plant General Manager
- R. Kitchen, Engineering Manager
- D. Makosky, Lead Nuclear Security Specialist
- J. McIntire, Equipment Performance Superintendent
- W. Noll, Director - Director of Site Operations
- E. ONeil, Manager - Site Support Services
- A. Pope, Superintendent-Systems Engineering
- E. Quidley, Manager - Outage and Scheduling
- S. Tabor, Lead Engineer - Technical Support
- H. Wall, Manager - Maintenance
- M. Williams, Manager - Operations
NRC Personnel
- P. Fredrickson, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II
- R. Bernhard, Senior Reactor Analyst, Division of Reactor Safety, Region II
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000324/2004002-01 AV Inadequate Corrective Actions for EDG Jacket Water Cooling Leak (Section 4OA2)
- 05000324/2004002-02 AV Failure to Meet TS LCO 3.8.1 (Section 4OA2)
Opened and Closed
- 05000325/2004002-03 NCV Inadequate Corrective Actions for EDG Jacket Water Cooling Leak Results in Failure to Meet TS LCO 3.8.1 (Section 4OA2)
Closed
- 05000324/2003006-02 URI Unit 2 Reactor Feed Pump Speed Control Modification (Section 4OA5.3)
50000325, 324/2002003-02 URI Failure of SCBA Training Program to Include Demonstration of Proficiency in SCBA Cylinder Change-
out (Section 4OA5.4)
Discussed
NONE