IR 05000327/2003004
| ML032090002 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 07/25/2003 |
| From: | Cahill S Reactor Projects Region 2 Branch 6 |
| To: | Scalice J Tennessee Valley Authority |
| References | |
| IR-03-004 | |
| Download: ML032090002 (54) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION uly 25, 2003
SUBJECT:
SEQUOYAH NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000327/2003004 AND 05000328/2003004
Dear Mr. Scalice:
On June 28, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Sequoyah Nuclear Power Plant, Units 1 and 2, including the steam generator replacement project on Unit 1. The enclosed report presents the results of the integrated inspection which were discussed on July 8, 2003, with Mr. Mike Lorek 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.
On the basis of the results of this inspection, no findings of significance were identified.
In accordance with 10 CFR 2.790 of the NRC's "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) components of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Stephen J. Cahill, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket No.: 50-327, 50-328 License No.: DPR-77, DPR-79
Enclosure:
(See page 2)
TVA 2 Enclosure: Inspection Report 05000327/2003004, 05000328/2003004 w/Attachment: Supplemental Information
REGION II==
Docket Nos: 50-327, 50-328 License Nos: DPR-77, DPR-79 Report No: 05000327/2003004, 05000328/2003004 Licensee: Tennessee Valley Authority (TVA)
Facility: Sequoyah Nuclear Plant, Units 1 & 2 Location: Sequoyah Access Road Soddy-Daisy, TN 37379 Dates: 4/06/2003 - 6/28/2003 Inspectors: S. Freeman, Senior Resident Inspector R. Telson, Resident Inspector T. Kolb, Project Engineer R. Carrion, Project Engineer (Sections 1R06, 1R12, 1R16)
S. Vias, Senior Reactor Inspector (Sections 1R08, 4OA5.1, 4OA5.3.1-10)
E. Testa, Senior Health Physicist (Sections 2OS1, 2OS2, 2PS2, 4OA1.2, 4OA1.3)
D. Jones, Senior Health Physicist (Sections 2OS1, 2OS2, 2PS2, 4OA1.2, 4OA1.3)
J. Kreh, Health Physicist (Sections 2OS1, 2OS2, 2PS2, 4OA1.2, 4OA1.3)
J. Lenahan, Senior Reactor Inspector (Sections 4OA5.4.5, 4OA5.4.6)
J. Ennis, Physical Security Inspector (Section 4OA5.3.11)
D. Holman, Physical Security Inspector, (Section 4OA5.3.11)
W. Sartor, Senior Emergency Preparedness Inspector (Sections 1EP2-5, 4OA1.4)
Approved by: S. Cahill, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000327/2003-004, IR 05000328/2003-004, 4/6/2003 - 6/28/2003, Sequoyah Nuclear
Power Plant, Units 1 & 2, resident inspector integrated report.
The report covered a three-month period of inspection by resident inspectors and region based Project Engineers and announced inspections by eight region based inspectors. It includes inspection of the Unit 1 steam generator replacement project. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.
A. NRC-Inspector Identified and Self-Revealing Findings None
Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status:
Unit 1 began the inspection period in a scheduled refueling and steam generator replacement outage. Outage activities were completed and the unit was taken critical on June 15, 2003.
The unit returned to 100 % rated thermal power on June 23, 2003.
Unit 2 operated at or near 100 % rated thermal power during the inspection period except for a reactor trip on April 12, 2003, due to problems in the turbine supervisory circuits. The problems were repaired and the unit returned to 100 % rated thermal power on April 15,
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors observed the licensee response to a tornado watch on May 5, 2003.
The inspectors reviewed licensee Procedure AOP-N.02, Tornado Watch/Warning, Revision 11, for its effectiveness to limit the risk of tornado-related initiating events and to adequately protect mitigating systems from the effects of a tornado. In addition, the inspectors verified the securing of large outside cranes in accordance with guidance in Topical Report 24370-TR-C-002, Rigging and Heavy Load Handling.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
The inspectors performed partial system walkdowns of the following three systems to verify the capability of redundant or diverse systems and components and that defense-in-depth was maintained during periods when safety equipment was inoperable. The inspectors reviewed applicable operating procedures, walked down control systems components and verified that identified problems were entered into the corrective action program.
- A-train and Turbine-Driven Train of Auxiliary Feedwater (AFW) during unavailability of Motor Driven AFW Pump 2B-B
- Cross-train Emergency Core Cooling Systems (ECCS) equipment during unavailability of 1A Essential Raw Cooling Water (ERCW) header
- A-train Containment Spray System during unavailability of Containment Spray (CS) Pump 2B
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors conducted a tour of the ten areas listed below to assess the material condition and operational status of fire protection. The inspectors verified that transient combustibles and ignition sources were controlled in accordance with the licensees administrative procedures, that fire protection equipment was available for use, and that fire barriers were intact. Documents reviewed are listed in the attachment.
- Control Building Elevation 706 (Cable Spreading Room)
- Essential Raw Cooling Water Building
- Control Building Elevation 685 (Reactor Protection Room)
- Auxiliary Building Elevation 714 (Component Cooling System (CCS) Heat Exchangers, Safety-related Chillers, and AFW level control valves)
- Auxiliary Building Elevation 653 (Unit 2 Residual Heat Removal (RHR) Pump Rooms)
- Emergency Diesel Generator Building
- Unit 1 Lower Containment Area
Turbines, Condenser Area)
- Auxiliary Building Elevation 690 (Penetration Room & Pipe Gallery)
- Switchyard (Common Station Service Transformers)
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors reviewed selected risk-important internal flood protection barriers to evaluate the adequacy of protecting risk-important equipment. The inspectors walked down the basement (Elevation 662') of the Unit 2 Turbine Building to assess the effectiveness of the licensees internal flooding mitigation program to protect susceptible systems and equipment. The inspectors evaluated the operability and material condition of internal flood protection-related components in the risk-significant areas to verify that the floor drain system was operable, including turbine building sump pumps A (0-PMP-40-1A) and B (0-PMP-40-1B), respectively, and the emergency portable sump pump (0-PMP-40-514).
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees execution and on-line monitoring of bio-fouling controls and cleanliness of the CCS Heat Exchanger 1A-2 plates during a routine inspection and cleaning. The inspectors directly examined the as-found and as-left condition of the opened heat exchanger for adverse conditions. The inspectors also reviewed corrective action documentation and interviewed personnel involved in the cleaning process to verify that the licensee was inspecting and cleaning the heat exchanger with sufficient frequency to detect conditions that could adversely affect its ability to remove heat.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection (ISI) Activities
a. Inspection Scope
The inspectors observed Unit 1, Cycle 12 in-process ISI work activities during the 2nd interval, 3rd ISI period, 1st outage and reviewed selected ISI records. The observations and records were reviewed for compliance to the Technical Specifications (TS) and the applicable Code (ASME Boiler and Pressure Vessel Code,Section XI, 1989 Edition, with 1995 Addenda). The following Unit 1 ISI examinations were observed/reviewed:
Penetrant (PT) 1-SIH-022-IA B-K B10.20 10" Cold Leg #4 CRDM #3 RVH CRDM #3 nozzle Visual (VT-3) 1-RHRH-007 F-A F1.10B 14" 1-CVCH-361 F-A F1.10B 3" Radiographic (RT) 1-RC-11-1 S/G 2 Safe end to elbow 1-RC-03-1 S/G 1 Safe end to elbow 1-RC-13-1 S/G 2 RCS CL 1-RC-18-1 S/G 3 RCS HL 1-RC-19-1 S/G 3 RCS CL Ultrasonic (UT) 1-MS-021-1 Main Steam to S/G 3 Nozzle/Elbow 1-RC-02 S/G 1 RCS HL 1-FW-131 S/G 3 to Feedwater Qualification and certification records for examiners, equipment and consumables, and nondestructive examination (NDE) procedures for the above ISI examination activities were reviewed. In addition, a sample of ISI issues in the licensees corrective action program were reviewed for adequacy. The following records/documents were reviewed:
NDE Examiner/QC Inspector Qualification Certification and Visual Acuity Records Examined Examiner Method-Level SW, TG VT-II, PT-II HD UT-III, PT-III SD PT-III PV, MP, PB, JP UT-II MH, DM, WT, JE, MG RT-II RT, DW, RP PT-II NDE Equipment and Consumables Probes: KBA- Model: Comp-G, SN:00W3MY KBA- Model: SWS-Comp, SN:00XJ58/00XJ59 Thermometer: T-26787 ID:573205; E27489; E26104; 558273 Scope: Krautkramer-Model USN-52L S/N:E30218 Krautkramer-Model USN-52L S/N:E21664 Cal Std.
6011137 A & B Cal Block: SQ-5, SQ-112, SQ-64 Couplant: 01225 Cleaner: SKC-S: 01B06K, 02B01K Penetrant: SKL-SP: 98M02K, SKL-SP1, SKL-WP Developer: SKD-S2: 96L0SK, 01G06K
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
The inspectors observed simulator training on June 25, 2003. The scenario involved a recoverable loss of condenser vacuum followed by a Loss of Coolant Accident (LOCA)with several component malfunctions. This placed the simulated unit in a functional response procedure for high containment pressure. The inspectors observed crew performance in terms of communications; ability to take timely and proper actions; prioritizing, interpreting and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high risk operator actions; oversight and direction provided by shift manager, including the ability to identify and implement appropriate Technical Specification (TS) actions; and group dynamics involved in crew performance. The inspectors also reviewed simulator fidelity to verify that it closely paralleled the recent steam generator replacement on Unit 1 or accounted for the differences between units.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the following two maintenance activities, which were identified because either they indicated equipment performance issues or affected equipment that performed high safety significant functions, to verify the effectiveness of the activities.
Documents reviewed are listed in the attachment.
- Emergency Diesel Generator (EDG) 1A-A and 2A-A unavailability in excess of maintenance rule performance criteria
- Maintenance of 6.9 kV Breakers
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors reviewed six activities to verify that the appropriate risk assessments were performed prior to removing equipment from service. When emergent work was performed, the inspectors verified that the risk for the work was assessed and required equipment was protected. The inspectors referenced Procedure SPP-7.1, Work Control Process, Revision 4, and Instruction, 0-TI-DSM-000-007.1, Equipment to Plant Risk Matrix, Revision 7, during these inspection activities.
- Removal of C station service and control air compressor for emergent maintenance
- Removal of Auxiliary Building Gas Treatment System (ABGTS) Train A from service for duct inspection
- Unavailability of CS System Train 2B due to recirculation lineup of Refueling Water Storage Tank (RWST)
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Non-Routine Plant Evolutions
a. Inspection Scope
During the seismic disturbance of April 29, 2003, the inspectors reviewed the operator logs, plant computer information, and associated Problem Evaluation Reports (PERs).
The inspectors also conducted interviews with operators to determine what occurred and how the operators responded, and to determine if the response was in accordance with the associated procedures. Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
For the five operability evaluations described in the PERs listed below, the inspectors evaluated the technical adequacy of the evaluations to ensure that operability was properly justified and the subject component or system remained available, such that no unrecognized increase in risk occurred. Documents reviewed are listed in the attachment.
- PER 02-005083-000, Shutdown Board 2B-B logic relay K609X
- PER 03-005768-000, Units 1, 2 Turbine Driven AFW pumps - Installation of incorrect low pressure steam traps
- PER 03-007360-000, Unit 1 Thermal Relief Valve blockage
- PER 03-008296-000, Siemens 6.9 kV Breaker Failed Receipt Inspection
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds (OWAs)
a. Inspection Scope
The inspectors reviewed the cumulative effects of deficiencies that constituted operator workarounds to determine whether or not they could affect the reliability, availability, and potential for misoperation of a mitigating system; affect multiple mitigating systems; or affect the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspectors also assessed whether OWAs were being identified and entered into the licensees corrective action program at an appropriate threshold. Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the eight post-maintenance tests listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the licensees test procedure to verify that the procedure adequately tested the safety function(s) that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with information in the applicable licensing-basis and/or design-basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed the test data, to verify that test results adequately demonstrated restoration of the affected safety function(s). Additional documents reviewed are listed in the attachment.
- WO 03-004376-000, Rework/Replace parts and/or controller and verify calibration of Unit 2 Steam Generator (SG) 1 Power-Operated Relief Valve (PORV) which opened spuriously following Unit 2 trip
- WO 03-002824-000, Replace erratic 6900V logic relay K609X which had erratic readings during surveillance testing
- 0-SI-SFT-072-138.0, Containment Spray-Spray Nozzle Test, Revision 3
- 1-STI-088-156.0, Primary Containment Vessel Post-Modification Pressure/New Weld Leakage Inspection Test, Revision 0
- 1-SI-SFT-065-001.B, Emergency Gas Treatment System Annulus Vacuum Draw Down Test Unit 1 Train B, Revision 5
- WO 01-03501-000, Remove and Replace Emergency Gas Treatment System (EGTS) ductwork
- WO 03-008636-000, Repair/Clean Pressure Control Valve 1-PCV-65-81
- 1-RT-MOD-520-002.0, 3 % Load Step Change, Revision 0
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities
a. Inspection Scope
Between April 6, 2003 and June 17, 2003, the inspectors observed portions of the refueling, heatup, and startup activities associated with the Unit 1 steam generator replacement outage to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS. The inspectors monitored licensee controls over the outage activities listed below and reviewed the licensees response to debris found in the reactor vessel during refueling activities. Documents reviewed during the inspection are listed in the attachment.
- Licensee configuration management, including daily outage reports, to evaluate defense-in-depth commensurate with the outage safety plan and compliance with the applicable TS when taking equipment out of service.
- Installation and configuration of reactor coolant instruments to provide accurate indication and an accounting for instrument error.
- Controls over the status and configuration of electrical systems and switchyard to ensure that TS and outage safety plan requirements were met.
- Decay heat removal processes to verify proper operation and that steam generators, when relied upon, were a viable means of backup cooling.
- Controls to ensure that outage work was not impacting the ability to operate the spent fuel pool cooling system during and after-core offload.
- Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.
- Reactivity controls to verify compliance with TS and that activities which could affect reactivity were reviewed for proper control within the outage risk plan.
- Containment closure for control of containment penetrations in accordance with refueling TS, to ensure that containment closure could be achieved during selected configurations, and to verify maintenance of secondary containment in accordance with TS.
- Refueling activities for compliance with TS, to verify proper tracking of fuel assemblies from the spent fuel pool to the core, and to verify foreign material exclusion was maintained.
- Removal activities associated with debris found during coreplate inspection on May 25, 2003, to verify that the evaluation of nineteen objects removed from and the nine objects left in the reactor pressure vessel after refueling would not impact operation of the unit.
- Reduced inventory and mid-loop conditions for commitments to Generic Letter 88-17 to verify that these commitments were in place, that plant configuration was in accordance with those commitments, and that distractions from unexpected conditions or emergent work did not affect operator ability to maintain the required reactor vessel level.
- Heatup and startup activities to verify that appropriate prerequisites for mode changes were met prior to changing modes, that containment integrity was established, that debris was not left that could affect the containment sump, and that core operating limit parameters were consistent with core design.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
For the six surveillance tests identified below, by witnessing testing and/or reviewing the test data, the inspectors verified that the systems, structures, and components involved in these tests satisfied the requirements described in the TS, the Updated Final Safety Analysis Report (UFSAR), and applicable licensee procedures, and that the tests demonstrated that the Systems, Structures, and Components (SSCs) were capable of performing their intended safety functions.
Documents reviewed are listed in the attachment. Those tests included the following:
- 0-SI-MIN-061-109.0, Ice Condenser Intermediate and Lower Inlet Doors and Vent Curtains, Revision 1
- 1-SI-ICC-003-042.4, Channel Calibration of Steam Generator 1 Level Channel IV, Rack 12, Loop L-3-42, Revision 6
- 1-SI-OPS-082-026.B, Loss of Offsite Power With Safety Injection - D/G 1B-B Test, Revision 26
- 1-SI-ICC-068-320.3, Channel Calibration of Pressurizer Level Channel III Rack 9, Loop L-68-320, Revision 11
- This procedure included inservice testing requirements.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the two temporary modifications described below, to verify that the design was adequate, the modification was properly installed, the modification did not affect system operability, drawings and procedures were appropriately updated, and post-modification testing was satisfactorily performed. Documents reviewed are listed in the attachment. Those modifications included the following:
- DCN EP-001, 002, WP&IR C-MHX-026, Unit 2 temporary airlock door
- TACF 1-03-0029-057, Inhibit Stator Ground Relay trip function
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert Notification System Testing
a. Inspection Scope
The inspector reviewed the alert (siren) and notification system (ANS) designed to meet the acceptance criteria of Section B of Appendix 3, NUREG-0654, and described in Section B.8 of Appendix B to the TVA NP (Nuclear Power) Radiological Emergency Plan (REP). The monthly complete cycle tests, bi-weekly silent tests, and annual growl tests were reviewed against the test frequencies commitments listed in paragraph B.8.1 of the REP.
The inspector reviewed testing results, assessed the failure rate of individual sirens and the effectiveness of repairs, and reviewed any changes related to the siren system.
b. Findings
No findings of significance were identified.
1EP3 Emergency Response Organization Augmentation Testing
a. Inspection Scope
The inspector reviewed Figure B-2 and Figure B-1 of the REP to determine the licensees commitment for on-shift and augmentation staffing respectively. The results of the off-hours augmentation drill, most recently conducted on November 2, 2002, were evaluated against the requirements listed in the notes to Figure B-1 of Appendix B to the REP.
b. Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The inspector reviewed the REP to identify any changes for review in accordance with the requirements of 10 CFR 50.54(q). There had been no changes made to the Sequoyah Appendix B since the last inspection.
b. Findings
No findings of significance were identified.
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies
a. Inspection Scope
The inspector evaluated the efficacy of licensee programs that addressed weaknesses and deficiencies in emergency preparedness. Items reviewed included exercise and drill critique reports, emergency preparedness assessment reports done by the Nuclear Quality Assurance, and the licensees Corrective Action Program. The review was conducted against the requirements listed in Section 14.4 and 16.4 of the NP-REP.
b. Findings
No findings of significance were identified.
RADIATION SAFETY
Cornerstones: Occupational Radiation Safety (OS) and Public Radiation Safety (PS) 2OS1 Access Control To Radiologically Significant Areas
.1 Access Control
a. Inspection Scope
The inspectors evaluated licensee activities for monitoring and controlling worker access to radiologically significant areas. The inspection included direct observation of administrative and physical controls, appraisal of the knowledge and proficiency of radiation workers and health physics technicians (HPTs) in implementing radiological controls, and review of the adequacy of procedural guidance and its implementation.
The inspectors observed implementation of radiological controls for selected Radiation Area (RA), Radioactive Material Area (RMA), and High Radiation Areas (HRA) locations within Radiologically Controlled Areas (RCAs). Area radiological posting and material labeling of materials at these locations were evaluated for consistency with procedural guidance and compliance with regulations. The inspectors directly observed the posting and locking status of selected Locked High Radiation Area (LHRA) locations in the Unit 1 (U1) and Unit 2 (U2) auxiliary buildings and the U2 lower containment.
Independent dose-rate measurements were taken in the U2 lower containment, radioactive waste (radwaste) processing and storage areas, and 1B-B containment spray heat exchanger room. Results of the independent measurements were compared to current licensee surveys.
The inspectors evaluated licensee performance during containment spray heat exchanger 1B-B maintenance and transfer of a used steam generator (S/G) from containment to its interim storage facility. The inspectors attended the heat exchanger maintenance pre-job briefing, evaluated the implementation of radiological controls, observed the HPTs and radiation workers performance, evaluated Radiation Work Permit (RWP) requirements and electronic dosimeter (ED) alarm setpoints, and discussed the task evolutions with selected personnel. During general observations of outage work, the inspectors queried radiation workers on RWP requirements associated with their tasks in progress.
The inspectors reviewed administrative guidance documents and procedures for control of material stored in spent fuel pools and LHRA locations, including access controls, posting, surveys, and RWP use. The inspectors reviewed selected RWPs and surveys of such areas to evaluate the adequacy of RA, HRA, and airborne area radiological controls. Health Physics supervision was interviewed regarding administrative control of LHRA keys, as well as changes to procedural guidance for access controls.
Radiation protection program activities and their implementation were evaluated against Title 10 Code of Federal Regulations (10 CFR) 19.12; 10 CFR Part 20, Subparts B, C, F, G, H, and J; and approved licensee procedures. Licensee procedures, records, and other documents reviewed within this inspection area are listed in Section 2OS1 of the report attachment.
b. Findings
No findings of significance were identified.
.2 Problem Identification and Resolution
a. Inspection Scope
Selected Problem Evaluation Reports (PERs) related to access control issues were reviewed in detail and discussed with Radiation Control (RadCon) supervision. The inspectors assessed the licensees ability to characterize, prioritize, and resolve the identified issues in accordance with licensee procedure TVAN Standard Programs and Processes, SPP-3.1, Corrective Action Program, Revision (Rev.) 4. Licensee documents evaluated during the inspection of this program area are listed in Section 2OS1 of the report attachment.
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning and Controls
.1 As Low As Reasonably Achievable (ALARA)
a. Inspection Scope
Implementation of the licensees ALARA program during the Unit 1 Steam Generator Replacement Refueling Cycle 12 was observed and evaluated by the inspectors. The inspection included evaluation of ALARA activities for high person-rem tasks, assessment of licensee source-term reduction efforts, and review of historical dose data. The reviewed high dose expenditure tasks included:
- Inspection of the reactor head
- Upper internals removal
- Lower internals replacement
- Steam Generator replacement
- Steam Generator Scaffold Removal The jobs and implementation of ALARA principles were observed via closed-circuit television and during tours of work sites. Projected dose expenditure was compared to actual dose expenditure values and noted differences were discussed with the ALARA staff. Changes to dose budgets relative to any changes in job scope were also discussed. The inspectors reviewed ALARA committee meeting minutes and evaluated ALARA initiatives for these and other outage jobs. The Steam Generator Replacement Project (SGRP) RadCon Handbook was also reviewed by the inspectors. The inspectors attended pre-job briefings and evaluated communication of ALARA goals, RWP requirements, and industry lessons-learned. Maintenance department understanding of dose budgets and ALARA concepts was assessed through discussions with radiation workers and job sponsors. Management support for ALARA was evaluated through interviews with ALARA staff and the RadChem Manager. The inspectors reviewed applicable procedural guidance and five exposure reduction plans to assess procedural and administrative guidance for ALARA activities.
The licensees source term reduction program, including cobalt reduction, was evaluated through discussions with the chemistry supervisor and review of dose rate trends for primary side piping. Selected parts of a temporary shielding procedure and the outage shielding plan were assessed. The inspectors interviewed the RadChem Manager and Chemistry Manager.
Historical dose data for collective exposure was reviewed from Fiscal Year (FY) 1999 through FY 2002. Dosimetry procedure guidance, as applicable, was reviewed to assess licensee controls for declared pregnant workers. Documents reviewed are listed in the attachment to this report.
The inspectors toured the onsite mock-up facility to evaluate the training of radiation workers engaged in specialized work activities associated with used steam generator removal and new generator installation. The inspectors also reviewed the Health Physics Emergency action plans for a Dropped SG Immediate Response Inside the Containment and Dropped SG Immediate Response Outside Containment.
The inspectors observed the rig-out of the U1 steam generator. The observation included independent surveys of RCA boundaries, installation of lay-down fixtures, rolling RCA dose control, operation of site exit portal monitors during transit, and dose surveys of exterior and inside mid-plane areas of the used steam generator storage facility. The inspectors independently verified evacuation and control of offices that were located inside the RCA during generator transit to the old steam generator storage facility. Surveys of the removal and transport of the other three old steam generators were evaluated for RCA dose control and worker doses received as measured by ED monitoring.
The licensees ALARA program was evaluated against the requirements of 10 CFR Part 20 and TS Section 5.4.1, Regulatory Guide (R.G) 1.33, Quality Assurance Program Requirements, as well as the guidance contained in R.G 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Stations Will Be As Low As Is Reasonably Achievable, and R.G 8.13, Instruction Concerning Prenatal Radiation Exposure.
b. Findings
No findings of significance were identified.
.2 Problem Identification and Resolution
a. Inspection Scope
Five licensee PERs and one self-assessment associated with ALARA activities were reviewed and assessed. The inspectors assessed the licensees ability to characterize, prioritize, and resolve the identified issues in accordance with licensee procedure TVAN Standard Programs and Processes, SPP-3.1, Corrective Action Program, Revision (Rev.) 4. Licensee documents evaluated during the inspection of this program area are listed in Section 2OS2 of the report attachment.
b. Findings
No findings of significance were identified.
2PS2 Radioactive Material Processing and Transportation
.1 Waste Processing and Characterization
a. Inspection Scope
The inspectors evaluated the operational status of selected liquid and solid radwaste processing systems and equipment. Inspection activities included document and record review, interviews with responsible plant personnel, and direct inspection of selected processing equipment and associated piping.
The inspectors observed the material condition and configuration of the systems and equipment used for spent resin and liquid radwaste processing. Systems and equipment abandoned in place were examined for isolation from systems in use and material condition. Operational radwaste processing system material condition and configurations were examined during facility tours. Procedural guidance for monitoring changes in waste streams; classifying radioactive wastes; and for transferring, sampling, and preparation of spent resins for temporary storage and final disposal was assessed.
Current records were reviewed to evaluate application of radwaste scaling factors and their supporting analyses for hard-to-detect radionuclides. The inspectors assessed the licensees procedure for transferring, sampling, and preparation of spent resins for temporary storage and final disposal.
Operational radwaste processing system equipment and configurations were inspected against system descriptions and process flow diagrams depicted in the UFSAR Section 11, Radioactive Waste Management. Radwaste processing and storage guidance was reviewed against UFSAR, Section 11.5, Solid Waste Management System, Process Control Program, Rev. 3, 10 CFR 61.55, and NRC Branch Technical Position documents on Radioactive Waste Classification dated May 1983 and January 1995. Reviewed procedures and records are listed in Section 2PS2 of the report attachment.
b. Findings
No findings of significance were identified.
.2 Transportation
a. Inspection Scope
The inspectors evaluated the licensees activities related to transportation of radioactive material. The evaluation included review of procedures and completed shipping records, assessment of worker knowledge and proficiency in shipping activities, and direct observation of shipment preparation activities.
The inspectors observed shipment preparations for a package containing contaminated laundry. Generation of shipping papers, package contact dose rates measurements, vehicle inspection, and driver instructions were observed by the inspectors.
Responsible staff were interviewed regarding package requirements, and radiation dose rate, and contamination limits. Current training records for individuals involved in transportation activities were reviewed.
Transportation program guidance and implementation were reviewed against regulations detailed in 10 CFR 71 and 49 CFR 170-189, and applicable licensee procedures. In addition, training activities were assessed against 49 CFR 172, Subpart H, and the guidance documented in NRC Bulletin 79-19. The reviewed procedures and records are listed in Section 2PS2 of the report attachment.
b. Findings
No findings of significance were identified.
.3 Problem Identification and Resolution
a. Inspection Scope
Issues identified through self-assessments and PERs associated with radwaste processing and radioactive material transportation activities were reviewed. The inspectors assessed the licensees ability to characterize, prioritize, and resolve the identified issues in accordance with licensee procedure SPP-3.1, Corrective Action Program, Rev. 4. Specific assessments, audits, and PERs reviewed and evaluated in detail for this inspection area are listed in Section 2PS2 of the report attachment.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
.1 Barrier Integrity Cornerstone
a. Inspection Scope
The inspectors sampled licensee submittals for the two PIs listed below for the period from April 1, 2002 through March 31, 2003. To determine the accuracy of the PI data reported for that period, guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, was used to verify the basis for reporting each indicator.
- Reactor Coolant System Activity
- Reactor Coolant System Leakage The inspectors reviewed portions of the operator and chemistry logs to verify that the licensee had accurately determined the Reactor Coolant System (RCS) activity and leakage during the previous four quarters for both units. The inspectors also observed the performance of Procedure 0-SI-OPS-068-137.0, RCS Water Inventory, which determines the amount of RCS leakage. Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2 Occupational Radiation Cornerstone
a. Inspection Scope
The inspectors reviewed the licensees records and data generated during the fourth quarter of 2002 and the first quarter of 2003 for the Occupational Exposure Control Effectiveness PI. The information reviewed included data reported to the NRC, pertinent corrective action program issues, and selected radiological control program records. Selected PERs initiated during the review period were reviewed and assessed for potential PI occurrences. The licensees disposition of the reviewed issues was evaluated against NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Rev. 2. Specific procedures, records, and PERs reviewed and evaluated for this PI verification are listed in Section 4OA1 of the attachment to this report.
b. Findings
No findings of significance were identified.
.3 Public Radiation Safety Cornerstone
a. Inspection Scope
The licensees records and data generated during the period October 2002 through March 2003 for the Radiological Effluent Control Performance Indicator (PI) were reviewed. The information reviewed included data reported to the NRC, pertinent corrective action program issues, and selected Radiological Effluent Control program records. The inspectors assessed the licensees monthly reviews for PI occurrences which were performed pursuant to procedure SPP-3.4, Performance Indicator for NRC Reactor Oversite Process, Rev. 0. The licensees disposition of the reviewed issues was evaluated against NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Rev. 2. Specific procedures, records, and PERs reviewed and evaluated for this PI are listed in Section 4OA1 of the report attachment.
b. Findings
No findings of significance were identified.
.4 Emergency Preparedness Cornerstone
a. Inspection Scope
On June 24-27, 2003, licensee records for Emergency Response Organization (ERO)Drill/Exercise Performance, ERO Drill Participation, and Alert and Notification System Reliability were reviewed to determine whether the submitted PI values through the first quarter of 2003 were calculated in accordance with the guidance contained in Section 2.4 (Emergency Preparedness Cornerstone) of NEI 99-02, Revision 2, "Regulatory Assessment Performance Indicator Guideline."
The inspector assessed the accuracy of the PI for ERO drill and exercise performance (DEP) over the past eight quarters through review of a sample of drill and exercise records. The inspector assessed the accuracy of the PI for ERO drill participation during the previous eight quarters for personnel assigned to key positions in the ERO.
The inspector assessed the accuracy of the PI for the alert and notification system reliability through review of a sample of the licensee s records of the monthly full cycle and bi-weekly silent tests.
b. Findings
No findings of significance were identified.
4OA3 Event Follow-up Unit 2 Reactor Trip
a. Inspection Scope
On April 12, 2003, following a Unit 2 reactor trip due to a spurious operation of the turbine high bearing vibration relay and turbine trip, the inspectors evaluated plant status, mitigating actions, and the licensees classification of the event, to enable the NRC to determine an appropriate NRC response. Pinched wiring in the turbine supervisory cabinet actuated the high vibration relay as operators were attempting to reset a status light. The event was reported to the NRC as event notification39753 and documented in the licensee corrective action program as PER 03-004354-000.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
.1 NRC Temporary Instruction (TI) 2515/150, Reactor Pressure Vessel Head and Vessel
Head Penetration Nozzles (NRC Bulletin 2002-02)
a. Inspection Scope
(TI 2515/150 and Order 03-009)
The inspectors observed activities relative to inspection of the Unit 1 reactor pressure vessel (RPV) head penetrations in response to NRC Bulletin 2002-02 and Order 03-009.
The guidelines and criteria for the inspection were provided in NRC temporary inspection (TI) procedure TI 2515/150, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles (NRC Bulletin 2002-02). The inspectors had previously reviewed the Unit 1 bare metal visual examination and documented their observations in Section 4OA5.1 of Inspection Report 50-327, 328/03-03. The inspection during the current inspection period included review of nondestructive examination (NDE) procedures, assessment of NDE personnel training and qualification, and observation and assessment of subsequent Ultrasonic (UT) and Liquid Penetrant (PT) examinations.
Discussions were also held with contractor representatives and licensee personnel. The inspectors reviewed licensee-identified boron deposits around CRD nozzle 3 and boron deposits on six CRD nozzles on the periphery of the head. The activities were examined to verify licensee compliance with regulatory requirements and gather information to help the NRC staff identify possible further regulatory positions and generic communications. Specifically, the inspectors reviewed or observed:
- (1) the in-process acquisition and analysis system of Accusonex UT circumferential blade probe examination data of reactor vessel head control rod drive (CRD) nozzles in the annulus between the outside surface of the thermal sleeve and the inner diameter (ID)of the nozzle; and
- (2) the resultant PT inspection of the J-groove weld and RPV head penetration nozzle base material of any area in question.
b. Findings and Observations
No findings of significance were identified, but the following documents the results of the inspectors verification activities for each section of the TI:
1) Verification that the examinations were performed by qualified and knowledgeable personnel.
The inspectors verified that NDE (UT & PT) inspections were being performed in accordance with approved and demonstrated procedures with trained and qualified inspection personnel. The inspectors reviewed the training and qualification records and determined that all the examiners had significant experience, including experience inspecting RPVs.
2) Verification that the examinations were performed in accordance with demonstrated procedures.
The inspectors verified by observation and discussions with the examination personnel that the licensees UT examinations for six nozzles (3, 53, 64, 65, 72, and 73) were examined in accordance with Framatome-ANP examination procedure - Remote Ultrasonic Examination of Reactor Head Penetrations, 54-ISI-100-09, Rev.
September 9, 2002. These examinations were performed beneath the vessel head using the U.S. Blade Probe Tool in conjunction with the Framatome-ANP ACCUSONEX automated data acquisition and analysis system. The ultrasonic probe used for performing the examinations, Circumferential Blade Probe, was inserted into the annulus between the outside surface of the thermal sleeve and the inner surface of the nozzle. After positioning the probe onto the nozzle inside surface, subsequent scanning was performed in the axial direction. Indexing of the probe was performed in the circumferential direction using a maximum two-degree increment for nozzle 3 and three-degree increment for the other 5 nozzles. The circumferential scan distance covered from minus five (-5) degrees to positive three hundred and sixty five (+365)degrees, yielding a ten degree overlap. De-mineralized water was used as the coupling agent between the transducer face and the nozzle surface.
The blade probe uses two 5.0 MHz elements, configured for forward scatter Time of Flight Diffraction (TOFD), to produce a 50E longitudinal wave looking in the axial direction of the nozzle. The TOFD technique provides detection and sizing information for inside surface and outside surface connected axial and circumferential flaws contained within the nozzle walls. Flaw detection is identified by signal loss from the lateral wave or back-wall response, as well as detection of crack tip responses.
In addition to the UT examination, the inspectors verified by observation by way of video and discussions with the examination personnel that a Liquid Penetrant (PT)examination was performed on CRD nozzle 3 from the outside surface, which included the weld and adjacent base material in accordance with Framatome ANP Nondestructive Examination Procedures - Liquid Penetrant Examination of Reactor Vessel Head Penetration J-Groove Welds, 54-ISI-250-00, Rev. February 8, 2002 and Visible Solvent Removable Liquid Penetrant Examination Procedure, 54-PT-6-07, Rev.
August 3, 2000.
The inspectors reviewed the Framatome ANP procedures and the licensees inspection plan, which were approved by Sequoyah management, for use for the RPV inspection.
The inspectors noted that the approved acceptance criteria and/or critical parameters for RPV leakage were applied in accordance with the procedures.
3) Verification that the licensee was able to identify, disposition, and resolve deficiencies.
The inspectors reviewed the vendor procedures controlling the PT and UT examination techniques and determined that they provided adequate guidance to ensure that they would be able to identify, disposition, and resolve relevant deficiencies in the RV head penetration materials. The inspectors verified that the examination results for each nozzle were individually documented.
4) Verification that the licensee was capable of identifying the primary water stress corrosion cracking (PWSCC) phenomenon described in the bulletin.
The inspectors reviewed, via remote camera/video, the licensees 6 UT & 1 PT examinations from below the RPV during the U1C12 outage; observed the licensee conduct the examination; discussed the examination with the licensee examiners prior to, during, and following the examination; and verified the qualifications of the licensee examination personnel. The UT NDE inspection techniques had been previously demonstrated capable of detecting PWSCC type manufactured cracks as well as cracks as documented in MRP 2002-107, Overview of RPV Head Penetration Inspection Demonstration Program, November 1, 2002. The inspectors concluded that the licensees visual examination was adequate to identify potential leakage resulting from PWSCC cracking of reactor head penetrations.
5) Evaluate condition of the reactor vessel head (debris, insulation, dirt, boron from other sources, physical layout, viewing obstructions).
See Paragraph 4OA5.1 of Inspection Report 05000327,328/2003003 for additional discussion of this area.
6) Evaluate ability for small boron deposits, as described in Bulletin 2001-01, to be identified and characterized.
See Paragraph 4OA5.1 of Inspection Report 05000327,328/2003003 for additional discussion of this area.
7) Determine extent of material deficiencies (associated with the concerns identified in the bulletins) which were identified that required repair.
All UT and PT NDE results indicated that there were no material deficiencies in any material reviewed. The PT on nozzle 3 was also independently reviewed by an outside consulting firm which concluded that the results were negative for any deficiencies that may have required any repair. No examples of RPV leakage or material deficiencies were identified during any NDE examinations.
8) Determine any significant items that could impede effective examinations.
No significant items that could impede the examination process were noted during observation of the NDE examinations.
9) Determine the basis for the temperatures used in the susceptibility ranking calculation.
See Paragraph 4OA5.1 of Inspection Report 05000327,328/2003003 for additional discussion of this area.
.2 (Closed) Unresolved Item (URI) 50-327, 328/02-02-05: Corrective Actions Related to the
Apparent Failure of Rod Cluster Control Assembly (RCCA) L-11 to Properly Insert.
This URI was opened following a reactor trip of Unit 2 on May 31, 2002, in which the RCCA at location L-11 apparently failed to properly insert into the core. The inspectors reviewed licensee PER 02-008088-000 and plant records of RCCA L-11 performance during six reactor shutdowns since the URI was opened.
The inspectors determined that PER 02-008088-000, provided an analysis that bounded the safety significance of the event. In this PER, the licensee addressed the following items:
- The impact on shutdown margin if all RCCAs stuck at 12, 20, and 30 steps and adequate margin for 12 and 20 steps. For 30 steps, subcriticality was demonstrated.
- Fuel manufacturing records showing that L-11 fuel assembly was not manufactured with excessive bowing or twist.
- Vendor information showing that RCCA finger tip swelling was not the likely cause of the occurrence, given drag testing results, age of RCCA, and trace characteristics for three RCCA drops.
- Mechanical interference or debris in guide tube as a potential likely cause.
The inspectors concluded that the PER adequately addressed the issue. No findings of significance were identified; therefore, this URI is closed.
.3.0 Unit 1 Steam Generator Replacement Project (SGRP)
.3.1 Engineering Preparation and Implementation for the SGRP
a. Inspection Scope
The inspectors reviewed engineering preparations including: selected Engineering Packages (EPs), calculations, analyses, drawings, Work Package and Inspection Reports (WP&IRs) and Design Change Notice (DCNs) for the Steam Generator Replacement Project (SGRP) in order to assess adequacy and completeness. The inspectors also held discussions with SGRP management to obtain a greater understanding of the entire project scope.
b. Findings
No findings of significance were identified.
.3.2 Project Management Organization and Staffing
a. Inspection Scope
The inspectors reviewed the SGRP organization including: controls for contractor oversight and interface, plans for identifying and resolving non-conforming conditions, and plans for implementing quality assurance requirements in order to assess adequacy. To evaluate the SGRP project management and organization, the inspectors reviewed various documents, including staffing reports, forecasts, and administrative procedures; and conducted interviews with various personnel in differing organizations.
b. Findings
No findings of significance were identified.
.3.3 SGRP Procedures and Documentation
a. Inspection Scope
To verify adequacy of SGRP procedures, the inspectors reviewed the Special Processes Manual (SPM) for Sequoyah Nuclear Plant Unit 1, Steam Generator Replacement Project, which contained procedures for welding and NDE matrices, procurement and control of welding filler materials, welder performance qualification standards, general welding standards, nondestructive examination standards, post weld heat treatment standards, weld documentation requirements, and welding procedure specifications.
Other procedures reviewed and compared with regulatory requirements and codes that were utilized during the SGRP are listed in the attachment.
b. Findings
No findings of significance were identified.
.3.4 Pre-Service Baseline Examination, Eddy Current (ET) of Replacement Steam
Generators
a. Inspection Scope
The inspectors reviewed the baseline eddy current data as issued in the Report on Steam Generator Eddy Current Examination and Repair, TVA Sequoyah Nuclear Power Plant Unit 1, Pre-Service Inspection, MRS-FSR-1216-TVA, Rev. 0, January 2003."
The inspectors reviewed aspects of the examination program for the Westinghouse Model 57AG steam generators, which included multifrequency bobbin testing for indications of degradation, loose parts, dents, etc., and motorized pancake/plus point testing for detection of anomalies in the tube sheet region, further evaluation of detected bobbin indications, and a plus point examination of the U-bend region for the first three rows. The inspection was to determine if all examinations were in compliance with NRC Regulatory Guide 1.83, TVA Sequoyah TS, and Sections V and XI of the 1995 ASME Code through the 1996 Addenda. The inspectors reviewed results of the examinations of the four steam generators, which required a total of 20 tubes to be plugged (4 in SG A, 6 in SG B, 5 in SG C, and 5 in SG D).
b. Findings
No findings of significance were identified.
.3.5 Review of SGRP Lifting and Transportation Program
a. Inspection Scope
The inspectors reviewed the adequacy of the SGRP lifting programs as described in 24370-EP-004, Rev.2, assuring that it was prepared in accordance with regulatory requirements, appropriate industrial codes, and standards; and verified that the maximum anticipated loads to be lifted would not exceed the capacity of the lifting equipment and supporting structures.
The inspectors examined the SGRP lifting equipment necessary to perform steam generator rigging and transport, design evaluation/erection/use and disassembly of the Outside Lift System (OLS), removal of the shield building dome concrete/containment vessel steel, and steam generator compartment concrete and load drop protection. The procedures and lifting documents that controlled the SGRP which were reviewed by the inspectors are listed in the attachment.
b. Findings
No findings of significance were identified.
.3.6 Haul Route Load Test and Evaluation
a. Inspection Scope
The inspectors reviewed the adequacy of the haul route evaluation, placement of temporary protection for plant commodities and haul route upgrades required to prepare the haul route for load testing and transport of the steam generators. The inspectors reviewed to verify that they had been prepared and tested in accordance with regulatory requirements, appropriate industrial codes, and standards.
The inspectors discussed the results of the transport path load testing with SGRP engineering personnel in order to determine that, where minor discrepancies occurred, these areas had been properly corrected with appropriate material.
b. Findings
No findings of significance were identified.
.3.7 Observation of SG Lifting and Movement
a. Inspection Scope
The inspectors observed various portions of the old steam generators (OSG) being lifted from the steam generator (S/G) cubicle through the temporary penetrations in the reactor building to the hydraulic trailer transporter. The inspectors also observed various portions of the replacement steam generators (RSG) being lifted from the hydraulic trailer transporter into containment. During these observations the inspectors performed visual inspections of the Outside Lift System and the hydraulic trailer transporter. For the task of rigging and movement of the SGs, the inspectors reviewed the WP&IRs for content, technical adequacy and to verify that appropriate line items had been signed off and that required pre-lift equipment inspections had been performed and documented in the enclosures provided. This review was also to verify that Industry Experience was utilized and reflected in the procedures.
b. Findings
No findings of significance were identified.
.3.8 Review and Walkdown on Engineering Preparation
a. Inspection Scope
The inspectors reviewed the installation of temporary pipe restraints; modification of the existing restraints; removal of snubbers and beams; and pipe cuts in order to verify that the engineering preparation for the removal of OSGs was in accordance with the engineering packages and drawings for the SGRP.
The inspectors performed a walk-through inspection of the Containment Building, to observe the cut reactor coolant piping from the S/G nozzles and observe housekeeping conditions around the work area. The inspectors looked at corrective actions to verify that problems identified early in the outage, associated with cleanliness, housekeeping, and control of materials and tools around the work area, were resolved.
b. Findings
No findings of significance were identified.
.3.9 Interference Removal and Restoration
a. Inspection Scope
The inspectors observed the vicinity of all S/G cavities before the lifting operation began to assure that the licensee had removed all of the interferences and restraints. The inspectors reviewed procedures which controlled the removal and re-installation of interferences. Provisions for the temporary storage of removed interference items were also reviewed. In addition, the inspectors observed portions of the removal of interferences including piping, steam generator restraints, snubbers, and lateral supports.
After the installation of the RSGs, the inspectors observed various portions of the re-installation of various items including (but not limited to); piping, steam generator restraints, snubbers, lateral supports, and instrumentation tubing to assure that they had been installed per the engineering drawings and procedures.
b. Findings
No findings of significance were identified.
.3.10 Special Procedures for Welding and Nondestructive Examination
a. Inspection Scope
1. Reactor Coolant System (RCS), Feedwater (FW), Main Steam (MS) and Steel
Containment Vessel (SCV) Fit-Up and Welding The inspectors conducted inspections of the fit-up and welding activities involving primary RCS, MS and FW piping, and the SCV. Activities were compared with appropriate Codes and Standards as listed in the attachment of this report and the Bechtel Special Process Manual (SPM).
The inspectors verified the as-built configuration and held discussions with cognizant engineering personnel. This inspection verified that the amount of movement and as-built gap associated with the cutting and fit-up of the RCS piping, for all four SGs, was within specification allowable tolerance requirements and applicable codes.
The inspectors observed the automatic welding of RCS hot-leg and cold-leg piping connections to all four steam generators RCS nozzles, and the connections for the MS and FW systems via video monitors on the control panels located outside containment.
The inspectors verified that the operator at the weld site and the operator at the control panel were in constant communication through head sets. The inspections during welding operations were to verify that the welding machine settings were being maintained within the qualified welding parameters listed in the welding procedure specification.
2. Training and Qualification
The inspectors observed work, examined selected records, and reviewed procedures to evaluate the licensees training and qualification efforts for personnel performing cutting, machining, welding, and NDE. The inspectors also reviewed the programs and compared them with the regulatory requirements and codes that were utilized during the SGRP, as discussed previously in this report.
NDE Examiner/QC Inspector Qualification Certification and Visual Acuity Records Examined Examiner Method-Level MH, DM, WT, JE, MG RT-II MP, PB, JP, PV UT-II Welder/Welding Operator Qualification Records Welder/Welding Operator Symbol M-71, M-55, M-50, M-35, M-29, M-19, M-63, M-59, M-33
3. Nondestructive Examination (NDE) & Post-Weld Heat Treatment
The inspectors evaluated the licensees welding, Nondestructive Examination (NDE) and Post-Weld Heat Treatment (PWHT) activities related to the SG replacement, by conducting an inspection of the records for calibration, examination results, fit-up, welding, certifications of personnel and materials, and NDE (including review of radiographs and UT data).
To verify that the radiographs showed the welds to be free of rejectable indications, the inspectors reviewed the radiographs of intermediate (root, hot pass, 1/3 and 2/3) and completed Reactor Coolant System (RCS), Feedwater (FW) and Main Steam (MS)welds to verify proper penetrameter type, size, placement, and sensitivity as well as film density, identification, quality, and weld coverage. The welds reviewed for this work effort was as follows:
Weld No.
Size NDE Type 1-RC-11-1 S/G 2 Safe end to elbow RT 1-RC-03-1 S/G 1 Safe end to elbow RT 1-RC-13-1 S/G 2 RCS CL RT 1-RC-18-1 S/G 3 RCS HL RT 1-RC-19-1 S/G 3 RCS CL RT 1-MS-021-1 Main Steam to S/G 3 Nozzle/elbow UT 1-FW-131 S/G 3 to Feedwater UT 1-RC-02 S/G 1 to RCS HL (elbow to safe-end) UT Records reviewed included WP&IRs, Field Welding Check Lists, Filler Material Withdrawal Authorizations, welding filler material Certified Material Test Reports, NDE Reports (UT and RT), UT consumables certifications, QC inspectors and NDE examiner certification and visual acuity documentation, and certification of visual acuity examiners qualification. Records were reviewed for completeness, accuracy and technical adequacy. The radiographs were examined for both film quality and acceptability.
b. Findings
No findings of significance were identified.
.3.11 Effect of Steam Generator Replacement Project (SGRP) on Site Security Program
a. Inspection Scope
During the period April 21-23, 2003, the inspectors evaluated the impact of the SGRP on the site physical security program. The inspectors observed protected area and vital area security boundaries affected by SGRP activities and evaluated compensatory measures implemented to control access through breaches in the barriers. The inspectors observed security posts which had been added for SGRP support and to meet the objectives of the site defensive strategy under outage conditions, evaluated security staffing for the outage, interviewed security officers to ascertain their knowledge and understanding of assigned duties, and evaluated the licensees assessment of the impact of SGRP activities on the site defensive strategy.
The licensees actions were evaluated against applicable portions of the site Physical Security Plan, security procedures, and the licensees commitments in response to the NRCs February 25, 2002, Order requiring the implementation of certain interim security compensatory measures.
Documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.4 Steam Generator Replacement (SGR) Inspection Overview
This inspection report documents completion of inspections required by IP 50001, Steam Generator Replacement Inspection, some of which were fulfilled by completion of baseline inspection procedures. The table below identifies and correlates specific IP 50001 inspection requirements examined during this inspection period with the corresponding sections of this report.
IP 50001 Section of Section Inspection Scope This Report 02.02.a.1.
Design changes and modifications to SSCs described in 4OA5.4.1 the UFSAR reviewed for compliance with 10 CFR 50.59 02.02.a.2.
Key design aspects and modifications for the replacement 4OA5.4.1 SGs and other Mods. associated with SG replacement 02.02.b. Engineering design, modification, and analysis associated 4OA5.3.5 with SG lifting and rigging 02.02.c. Radiation protection program controls, planning, and 2OS1, 2OS2 preparation 02.02.d.1. Security considerations associated with vital and 4OA5.3.11 protected area barriers that may be affected during replacement activities 02.02.d.2. Controls and plans to minimize any adverse impact on the 1R20, operating unit and common systems 4OA5.4.2 02.03.a.1. Special procedures for welding and Non-Destructive 4OA5.4.6, Examination (NDE) 4OA5.3.10 02.03.a.2. Training and qualifications for welding and NDE personnel 4OA5.3.10 02.03.a.3. NDE results and work packages for selected welds 4OA5.3.10 02.03.a.4. Completion of pre-service NDE requirements for welds 4OA5.3.10 and baseline eddy current examination of new SG tubes 02.03.b. Activities associated with lifting and rigging 4OA5.3.5, 4OA5.3.7 02.03.c. Major structural modifications to facilitate SG replacement 4OA5.4.6 02.03.d. Restoration of temporary containment opening and 4OA5.4.5 containment leakage testing 02.03.e.1. Establishment of operating conditions including defueling, 1R20, RCS draindown, system isolation and safety tagging 4OA5.4.3 02.03.e.2. Implementation of radiation protection controls 4OA5.4.3, 2OS1, 2OS2 02.03.e.3. Controls for excluding foreign materials in the primary and 1R20, secondary side of the SGs and in related RCS openings 4OA5.4.3 02.03.e.4. Installation, use, and removal of temporary services 1R20, 4OA5.4.3 02.03.f. Radiological safety plans for temporary storage or 2OS1, disposal of retired SGs and components 2OS2, 2PS2 02.04.1. Post-installation containment testing 1R19, 1R20 4OA5.4.4 02.04.2. Post-installation inspections and verifications 4OA5.4.4 02.04.3. RCS leakage testing 4OA5.4.4 02.04.4. SG secondary side leakage testing 4OA5.4.4 02.04.5. Calibration and testing of instrumentation 1R22, 4OA5.4.4 02.04.6. Procedures for equipment performance testing 1R19, 4OA.4.4 02.04.7. Preservice inspection of new welds 4OA5.3.10
.4.1 SGR Design Changes and Modifications - 10 CFR 50.59 Review
a. Inspection Scope
As required by IP 50001, Sections 02.02.a.1 and 02.02.a.2, the inspectors reviewed design change notice, D-20672, SG Vessel Replacement/RCS Support Modifications, Revision A, for key design aspects and modifications of the replacement steam generators and verified that changes to the facility as described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59. To complete these reviews, the inspectors used IP 71111.02 as guidance.
b. Findings
No findings of significance were identified.
.4.2 SGR Controls to Minimize Adverse Impact on Operating Unit
a. Inspection Scope
As required by IP 50001, Section 02.02.d.2, throughout this inspection period, the inspectors reviewed and monitored licensee controls and plans to minimize any adverse impact on the operating unit and common systems. Specific areas reviewed included:
- Modifications to the auxiliary building secondary containment envelope (ABSCE)
b. Findings
No findings of significance were identified.
.4.3 SGR Operating Conditions, Radiation Protection Controls, Foreign Material Exclusion,
and Temporary Services
a. Inspection Scope
As required by IP 50001, Section 02.03.e, throughout this inspection period, the inspectors routinely inspected the following activities as they occurred:
- Establishment of operating conditions including defueling, RCS draindown, and system isolation and safety tagging/blocking.
- Implementation of radiation protection controls.
- Implementation of controls for excluding foreign materials in the primary and secondary side of the SGs and in the related RCS openings.
- Installation, use, and removal of temporary services directly related to steam generator replacement activities.
b. Findings
No findings of significance were identified.
.4.4 Post-Installation and Verification and Testing Inspections
a. Inspection Scope
As required by IP 50001, Section 02.04, the inspectors reviewed and monitored the following nine post-installation and activities. Some of these tests were reviewed as part of the baseline inspection program.
- 1-STI-088-156.0, Primary Containment Vessel Post-Modification Pressure/New Weld Leakage Inspection Test, Revision 0
- 1-SI-SFT-065-001.B, Emergency Gas Treatment System Annulus Vacuum Draw Down Test Unit 1 Train B, Revision 5
- 0-SI-OPS-000-187.0, Containment Inspection, Revision 21
- 0-SI-SFT-072-138.0, Containment Spray-Spray Nozzle Test, Revision 3
- 1-RT-MOD-520-001.0, Steam Generator Replacement Post - Modification Test Sequence, Revision 0
- 1-SI-SXI-068-201.0, Leakage Test of the Reactor Coolant Pressure Boundary, Revision 4
- 0-SI-SXI-000-201.0, American Society of Mechanical Engineers (ASME)Section XI Inservice Pressure Test, Revision 11
- 1-SI-ICC-003-042.4, Channel Calibration of Steam Generator 1 Level Channel IV, Rack 12, Loop L-3-42, Revision 6
- 1-RT-MOD-520-002.0, 3 % Load Step Change, Revision 0
b. Findings
No findings of significance were identified.
.4.5 Containment Restoration Activities
a. Inspection Scope
The inspectors reviewed containment restoration activities associated with two temporary construction openings in the containment shield building dome and steel containment vessel, which were approximately 20 feet by 40 feet, for the Unit 1 steam generator replacement project.
The inspectors reviewed procedures for installation of concrete reinforcing steel and Bar-Lock splices and procedures for control of concrete placement activities. The inspectors observed installation of concrete reinforcing steel and installation of Bar-Lock splices to determine if the work was completed in accordance with requirements shown on design drawings. The inspectors reviewed results of quality control acceptance testing performed on materials (cement, fine and coarse aggregate, water, and admixtures) selected for batching the concrete and results of qualification testing for the Bar-Lock splices. The inspectors also reviewed the concrete mix data to ensure that selected trial mix met concrete design strength requirements, and that Quality Control (QC) acceptance criteria specified in the procedures for the plastic concrete were based on the trial mixes.
The inspectors reviewed the restoration of the steel containment vessel welding procedures and weld process sheets. The inspectors observed in-process welding activities, reviewed the licensees program for control of weld filler materials, and observed preliminary preparations for performance of radiographs of the completed welds on the steel containment vessel. Welding acceptance criteria were specified in Bechtel General Welding Standard GWS-1 and American Welding Society AWS D1.1, Structural Welding Code.
b. Findings
No findings of significance were identified.
.4.6 Steam Generator Enclosure Roof Restoration
a. Inspection Scope
The inspectors reviewed drawings and observed work activities for restoration of the steam generator enclosure roofs after replacement of the Unit 1 steam generators.
The inspectors examined the structural steel support frames installed to support the plugs removed from the enclosure roofs for access to replace the steam generators.
Acceptance criteria for the restoration of the enclosure roofs were specified on the design drawings.
b. Findings
No findings of significance were identified.
4OA6 Meetings, including Exit
On July 8, 2003, the resident inspectors presented the inspection results to Mr. Mike Lorek and other members of his staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided nor retained during the inspection.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- J. Bajraszewski, Licensing Engineer
- T. Carson, Maintenance and Modifications Manager
- H. Cothran, Steam Generator Manager
- E. Freeman, Operations Manager
- J. Gates, Business & Work Performance Manager
- M. Gillman, Operations Manager
- C. Kent, Radcon/Chemistry Manager
- D. Koehl, Plant Manager
- M. Lorek, Assistant Plant Manager
- D. Lundy, Site Engineering Manager
- R. Purcell, Site Vice President
- R. Rogers, Design Manager
- P. Salas, Licensing and Industry Affairs Manager
- J. Smith, Site Licensing Supervisor
- K. Stephens, Security Manager
NRC personnel
- S. Cahill, Chief, Reactor Projects Branch 6
- R. Bernard, Region II, Senior Reactor Analyst
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed
None
Closed
50-327,328/02-02-05 URI Corrective Actions Related to the Apparent Failure of RCCA L-11 to Properly Insert (Section 4OA5.2)
Discussed
None