IR 05000266/2004004

IR 05000266-04-004, 05000301-04-004, on 06/28/2004 - 07/16/2004; Point Beach Nuclear Plant, Units 1 & 2; Safety System Design and Performance Capability

ML042510353
Person / Time
Site:	Point Beach
Issue date:	09/07/2004
From:	Reynolds S Division Reactor Projects III
To:	Koehl D Nuclear Management Co
References
IR-04-004
Download: ML042510353 (71)

Text

September 7, 2004 Mr. Dennis L. Koehl Site Vice-President Point Beach Nuclear Plant Nuclear Management Company, LLC 6610 Nuclear Road Two Rivers, WI 54241-9516 SUBJECT: POINT BEAC H NUC LEAR PLAN T, UNITS 1 AND 2 NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION 05000266/2004004(DRS); 05000301/2004004(DRS)

De ar M r. Ko ehl:

On July 16, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed a baseline inspection at your Po int Beach Nu clear P lant, Un its 1 and 2. Th e enclosed report docum ents the inspection findings, which were discussed on July 16, 2004, with you and members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Specifically, this inspection focused on the design and performance capability of the service water and 480 V ac system s. W e noted that design modifications that you have m ade to the service water system have enhanced the system=s operational ava ilability and reliability.

The inspection team did identify several exa mples where design outputs were not properly translated into field documents. The team also identified examples which illustrated knowledge and program implementation deficiencies pertaining to certain AS ME Co de standards.

Collectively, these inspection findings illustrated the continuing challenge which remains for the engineering organization. W e will continue to monitor your progress in implementing engineering program improvements as part of ou r Confirmatory Action Letter fo llow-up activities.

In addition, fou r Ac tion Plan steps of your Excellence Plan were reviewed during the inspection.

The reviews conducted during this inspection were in-pro gress assessments with the fu ll effectiveness of the Action Plans being assessed during future follow-up inspections.

Based on the resu lts of this inspection, six findings of ve ry low safety significance (Gre en) were identified which were also determined to involve violations of NRC requirements. Because these violations were of very low safe ty significance and because they have been entered into your corrective a ction program , the NR C is treating these findings as N on-Cited Violations in accordance with Se ctio n V I.A.1 o f the N RC's Enforcement Policy.

If you contest the subject or severity of the Non-Cited Violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S . Nu clear R egulatory C om mission, AT TN: D ocum ent Co ntrol De sk, W ashington,

D. Koehl -2-DC 20555-0001, with a copy to the Re gion al Adm inistrato r, U.S. Nuclear Regulatory Co mmission - Region III, 24 43 W arrenville R oad, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, W ashington, DC 20555-0001; and the Re sident Inspector Office at the P oint Be ach N uclear Pla nt.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NR C P ublic Docum ent Room or from the Publicly Available Records (PARS) component of NRC 's document system (ADAMS). ADAMS is accessible from the NRC W eb site at http://www.nrc.gov/reading-rm/adams.html (the P ublic Electron ic Reading Ro om ).

Sincerely,

/RA/

Steven A. Reynolds, Acting Director Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27 Enclosure: Inspection R eport 05000266/2004004(DRS );

05000301/2004004(DRS)

cc w/encl: F. Kuester, President and Chief Executive Officer, W e Generation J. Cowan, Executive Vice President Chief Nuclear Officer D. Cooper, Senior Vice President, Group Operations D. W eaver, Nuclear Asset Manager Plant Manager Regulatory Affairs Manager Training Manager Site Assessment Manager Site Engineering Director Emergency Planning Manager J. Rogoff, Vice P residen t, Counsel & Secretary K. Duveneck, Town Chairman Town of Two Creeks Chairperson Pu blic Se rvice Co mmission of W isconsin J. Kitsembel, Electric Division Pu blic Se rvice Co mmission of W isconsin State Liaison Officer

D. Koehl -2-DC 20555-0001, with a copy to the Re gion al Adm inistrato r, U.S. Nuclear Regulatory Co mmission - Region III, 24 43 W arrenville R oad, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, W ashington, DC 20555-0001; and the Re sident Inspector Office at the P oint Be ach N uclear Pla nt.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NR C P ublic Docum ent Room or from the Publicly Available Records (PARS) component of NRC 's document system (ADAMS). ADAMS is accessible from the NRC W eb site at http://www.nrc.gov/reading-rm/adams.html (the P ublic Electron ic Reading Ro om ).

Sincerely,

/RA/

Steven A. Reynolds, Acting Director Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27 Enclosure: Inspection R eport 05000266/2004004(DRS );

05000301/2004004(DRS)

cc w/encl: F. Kuester, President and Chief Executive Officer, W e Generation J. Cowan, Executive Vice President Chief Nuclear Officer D. Cooper, Senior Vice President, Group Operations D. W eaver, Nuclear Asset Manager Plant Manager Regulatory Affairs Manager Training Manager Site Assessment Manager Site Engineering Director Emergency Planning Manager J. Rogoff, Vice P residen t, Counsel & Secretary K. Duveneck, Town Chairman Town of Two Creeks Chairperson Pu blic Se rvice Co mmission of W isconsin J. Kitsembel, Electric Division Pu blic Se rvice Co mmission of W isconsin State Liaison Officer DOCU MENT N AME: G:\DRS\W ork in Progress\Poi 2004 004 DRS.wpd To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RIII RIII RIII RIII NAME SB urgess:jb PLouden JLara SReynolds DATE 08/11/04 08/30/04 08/24/04 09/07/04 OFFICIAL RECORD COPY

D. Koehl -3-ADAMS D istribution:

W DR DFT HKC RidsNrrDipmIipb GEG HBC PGK1 CAA1 C. P ederson, DR S (h ard copy - IR =s only)

DR PIII DR SIII PLB1 JRK1 ROPreports@nrc.gov

U.S. NUCLEAR REGULATORY COMMISSION RE GION III Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2004004(DRS); 05000301/2004004(DRS)

Licensee: Nuclear Management Company, LLC Fa cility: Point Beach Nuclear Plant, Units 1 and 2 Location: 6610 Nuclear Road Two Rivers, WI 54241 Dates: June 28 through July 16, 2004 Inspectors: S. Burgess, Senior Reactor Analyst/Team Leader C. Baron, Mechanical Contractor M. Holmberg, Engineering Inspector A. Klett, Engineering Inspector J. Neurauter, Engineering Inspector G. O=Dwyer, Engineering Inspector G. Skinner, Electrical Contractor N. Valos, Operations Inspector R. W inter, Engineering Inspector Ob server: J. Bond, Nuclear Safety Professional Ap proved by: J. Lara, Chief Electrical Engineering Branch Division of Reactor Safety (DRS)

Enclosure

SUMMARY OF FINDINGS

IR 05000266/2004004(DRS); 05000301/2004004(DRS); 06/28/2004 - 07/16/2004; Point Beach

Nuclear Plant, Units 1 & 2; S afety S ystem Design and P erformance Capability.

The inspection was a three week baseline inspection of the design and performance capability of the service water and 480 Vac systems. The inspection was conducted by regional engineering inspectors and a mechanical and electrical consultant. Six issues of very low safety significance were identified. The significance of most findings is indicated by their color (Green, W hite, Yellow, Re d) using Inspection Ma nual C hapter 0609, ASignificance 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 o peration of commercial nuclear power rea ctors is described in NUREG -1649, "Reactor Oversight Process," Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

C

Green.

The inspectors identified a Non-Cited Violation of 10 CFR 50.55a(g)(4) and 10 CFR 50.55a(g)(5)(iv) associated with failure to perform testing of the buried service water header piping in accordance with the American Society of Mechanical Engineers Code Section XI requirements. The licensee=s corrective actions included verifying that quarterly system flow tests provided basis for service water header operability.

This finding was more than minor because it affected the Mitigating Systems Cornerstone objective of equipment reliability and if left uncorrected, could have allowed undetected through-wall flaws to develop in the header piping. These flaws could then continue to grow in size until leakage from the buried headers degraded system operation or if sufficient general corrosion occurs, a gross rupture or collapse of the piping sections could occur. The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.2b.1)

C

Green.

The inspectors identified a Non-Cited Violation of 10 CFR 50.55a(g)(4)associated with failure to conduct non-destructive examinations and repair of valve SW 0322 in accordance with American Society of Mechanical Engineers Code Section XI requirements. The licensee=s corrective actions included replacement of the valve during the next opportunity.

This finding was more than minor because it affected the Mitigating Systems Cornerstone objective of equipment reliability and if left uncorrected, could have allowed unacceptable base metal flaws to remain in service. Additionally, the failure to heat treat the weld repairs could have resulted in high welding residual stresses and untempered martensite formation. Untempered martensite is a hard brittle phase of steel (e.g., not flaw tolerant) and can serve to allow rapid crack propagation that could jeopardize the pressure retaining function of the valve body. The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.2b.2)

C

Green.

The inspectors identified a Non-Cited Violation of 10 CFR 50.55a(g)(4)associated with failure to implement the American Society of Mechanical Engineers Code Section XI examinations and repair requirements for service water pump discharge check valves SW 32C and SW 32F. The licensee=s corrective actions included verifying that quarterly surveillance tests verified check valve operability.

This finding was more than minor because it affected the Mitigating Systems Cornerstone objective of equipment reliability and if left uncorrected, the failure to perform the required examinations could have allowed unacceptable base metal flaws to remain in-service. Additionally, the failure to select and follow a repair Code or standard may have resulted in inadequate post weld heat treatments for the weld repairs that could result in high welding residual stresses and untempered martensite formation.

Untempered martensite is a hard brittle phase of steel (e.g., not flaw tolerant) and can serve to allow rapid crack propagation which could jeopardize the pressure retaining function of these valve disks. The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.2b.3)

$

Green.

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion III, ADesign Control,@ in that, the design bases for the maximum Condensate Storage Tank (CST) temperature was not correctly translated into procedures and instructions. Specifically, the Main Steam Line Break (MSLB) Containment Integrity Analysis assumed a maximum value of 100EF for the temperature of the water in the CST, while operations procedures allowed a maximum of 120EF for the CST temperature. This finding applies to both units. The licensee=s corrective actions included procedural changes to reflect the correct temperature limit.

This finding was more than minor because an evaluation was required to ensure that accident analysis requirements were met, since the CST was heated up to greater than the maximum analysis value of 100EF during unit startup/shutdown operations with the CST aligned to the operating unit. The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.2b.4)

$

Green.

The inspectors identified a Non-Cited Violation of Technical Specification Surveillance Requirements SR 3.7.8.1 and SR 3.6.3.2 associated with the periodic verification of the position of valves and flanges in the service water (SW) system flow paths servicing safety related equipment and in lines associated with containment isolation. Specifically, the licensee did not verify that approximately 100 valves in the

SW system flow path servicing safety related equipment that were not locked, sealed, or otherwise secured in position, were in the correct position every 31 days while the Units were in Mode 1, 2, 3, or 4. In addition, the licensee did not verify that 12 containment isolation manual valves were closed and two pipe fittings associated with containment isolation were in place every 31 days while the Units were in Mode 1, 2, 3, or 4. This finding applies to both units. The licensee=s corrective actions included locking the appropriate valves and procedural changes.

This finding was more than minor because it was, for the most part, associated with the Mitigating Systems attribute of Configuration Control, which affected the Mitigating Systems Cornerstone objective of ensuring the availability and reliability of the service water (SW) system to respond to initiating events to prevent undesirable consequences.

The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.2b.5)

$

Green.

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion III, ADesign Control,@ for the licensee=s failure to adequately translate original design requirements for the 480 Vac system into specifications during procurement of new and replacement equipment. The original specifications for equipment such as motors and cables identified the intended service as suitable for a 480 Vac ungrounded system. Specifications for replacement motors did not specify the intended service as an ungrounded system. The licensee=s corrective actions included a verification that the identified equipment that did not specify use in a 480 Vac ungrounded system could withstand the overvoltage conditions that can occur on ungrounded systems.

This finding was more than minor because it involved the design control attribute of the Mitigating Systems cornerstone and affected the objective of ensuring the capability of the safety related 480 Vac system in response to initiating events to prevent undesirable consequences. Specifically, the failure to specify the correct service conditions may have resulted in motors being supplied without the enhanced insulation systems required to withstand the overvoltage conditions that can occur on ungrounded systems when a single line to ground occurs. The finding is of very low safety significance and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.3b)

Licensee-Identified Violations

None.

REPORT DETAILS

1R21 Safety System Design and Performance Capability

Introduction:

Inspection of safety system design and performance verifies the initial design and subsequent modifications and provides monitoring of the capability of the selected systems to perform design bases functions. As plants age, the design bases may be lost and important design features may be altered or disabled. The plant risk assessment model is based on the capability of the as-built safety systems to perform the intended safety functions successfully. This inspectable area verifies aspects of the mitigating systems cornerstone for which there are no indicators to measure performance.

The objective of the safety system design and performance capability inspection is to assess the adequacy of calculations, analyses, other engineering documents, and operational and testing practices that were used to support the performance of the selected systems during normal, abnormal, and accident conditions.

The systems and components selected were the service water (SW) and 480 Vac systems (two samples). These systems were selected for review based upon:

$ having high probabilistic risk analysis rankings;

$ considered high safety significant maintenance rule systems; and

$ not having received recent NRC review.

The criteria used to determine the acceptability of the system=s performance was found in documents such as:

$ licensee technical specifications (TS);

$ applicable updated final safety analysis report (UFSAR) sections; and

$ the systems' design documents.

The following system and component attributes were reviewed in detail:

System Requirements Process Medium - water; Energy Source - electrical power, steam, air; Control Systems - initiation, control, and shutdown actions; Operator Actions - initiation, monitoring, control, and shutdown; and Heat Removal - ventilation.

System Condition and Capability Installed Configuration - elevation and flow path operation; Operation - system alignments and operator actions; Design - calculations and procedures; and Testing - flow rate, pressure, temperature, voltage, and levels.

Component Level Equipment Qualification - temperature and radiation; and Equipment Protection - seismic and electrical.

.1 System Requirements

a. Inspection Scope

The inspectors reviewed the UFSAR, TS, system notebooks, lesson plans, drawings, and other available design basis information, as listed in the attached List of Documents, to determine the performance requirements of SW and the 480 Vac systems. The reviewed system attributes included process medium, energy sources, control systems, operator actions, and heat removal. The rationale for reviewing each of the attributes was:

Process Medium: This attribute required review to ensure that the SW system would supply the required amount of water to the safety-related equipment following normal transients and design basis events.

Energy Sources: This attribute needed to be reviewed to ensure that the SW and 480 Vac systems would function when called upon, and that appropriate SW valves would have sufficient power to change state when so required.

Controls: This attribute required review to ensure that the automatic controls for the SW and 480 Vac systems were properly established. Additionally, review of alarms and indicators of off-normal conditions was necessary to ensure that operator actions would be accomplished in accordance with the design.

Operations: This attribute was reviewed because operator actions played an important role ensuring that the selected systems would accomplish their safety functions.

Heat Removal: This attribute was reviewed to ensure that pump bearings were adequately cooled and that room coolers provided sufficient heat removal capability for equipment needed for accident mitigation.

b. Findings

No findings of significance were identified.

.2 System Condition and Capability

a. Inspection Scope

The inspectors reviewed design basis documents and plant drawings, abnormal and emergency operating procedures, requirements, and commitments identified in the UFSAR and TS. The inspectors compared the information in these documents to applicable electrical, instrumentation and control, and mechanical calculations, setpoint changes, and plant modifications. The inspectors also reviewed operational procedures to determine whether instructions to operators were consistent with design assumptions.

The inspectors reviewed information to determine whether the actual system condition and tested capability was consistent with the identified design bases. Specifically, the inspectors reviewed the installed configuration, the system operation, the detailed design, and the system testing, as described below.

Installed Configuration: The inspectors determined that the installed configuration of the SW and 480 Vac systems met the design basis by performing detailed system walkdowns. The walkdowns focused on the installation and configuration of piping, components, and instruments; the placement of protective barriers and systems; the susceptibility to flooding, fire, or other environmental concerns; physical separation; provisions for seismic and other pressure transient concerns; and the conformance of the currently installed configuration of the systems with the design and licensing bases.

Operation: The inspectors performed a procedure walk-through of selected manual operator actions to determine if the operators had the knowledge and tools necessary to accomplish actions credited in the design basis.

Design: The inspectors reviewed the mechanical, electrical, and instrumentation design of the SW and 480 Vac systems to determine whether the systems would function as required under design conditions. This included a review of the design basis, design changes, design assumptions, calculations, boundary conditions, and models as well as a review of selected modification packages. Instrumentation was reviewed to determine appropriateness of applications and setpoints based on the required equipment function.

Additionally, the inspectors performed limited analyses in several areas to determine the appropriateness of the design values.

Testing: The inspectors reviewed records of selected periodic testing and calibration procedures and results to determine whether the design requirements of calculations, drawings, and procedures were incorporated in the system and were adequately demonstrated by test results. Test results were also reviewed to ensure automatic initiations occurred within required times and that testing was consistent with design basis information.

b. Findings

b.1 Failure to Perform Code Testing to Confirm the Integrity of Buried Service Water Headers

Introduction:

The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50.55a(g)(4) and 10 CFR 50.55a(g)(5)(iv) having very low safety significance (Green)for failure to perform testing of the buried SW header piping in accordance with the American Society of Mechanical Engineers (ASME) Code Section XI requirements.

b.1.1 Failure to Test Service Water Headers During Last Code Interval

Description:

The Unit 1 and 2 SW systems contain a buried 31-inch diameter header that carries service water from the pump house to SW system loads in the auxiliary and turbine buildings. These buried headers were installed with protective coatings applied to the exterior of the piping, but were not actively protected from corrosion by a cathodic protection system. Therefore, the only means of confirming that interior or exterior corrosion had not affected the pressure retaining integrity of this piping was through periodic testing required by the Section XI of the ASME Code. The inspectors identified that this periodic testing had not been performed.

On July 1, 2004, the inspectors identified that the licensee had not performed the periodic pressure drop test or change in flow rate test to confirm the integrity of the buried SW headers as required by 1986 Edition of Section XI, IWA-5244 (the licensee was committed to this Edition of the ASME Code during the previous Code Inservice Inspection (ISI) interval). The licensee acknowledged that the 1986 Code Edition requirements were not met, but considered that compliance with the current requirements was achieved for nonisolable buried pipe as identified in the 1998 Edition through 2000 Addenda of Section XI (see Section b.1.2). Therefore, the licensee documented in CAP 057701 that this was an administrative issue and that there were no operability concerns.

The inspectors questioned the licensee staff as to why a failure to complete Code testing was an administrative issue. This question prompted the licensee staff to initiate a second CAP 057789, in which the licensee staff documented that the quarterly system flow test (IT-7) provided the basis for confirming SW header operability (e.g., no gross leakage existed because the SW system flow was above minimum requirements).

Analysis:

The inspectors determined that the failure to perform the required periodic testing of the buried SW headers or request NRC relief from the ASME Code requirements was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, APower Reactor Inspections Reports,@

Appendix B, AIssue Disposition Screening,@ because, if left uncorrected, the failure to perform the required periodic tests could have allowed undetected through-wall flaws to develop. These flaws could then continue to grow in size until leakage from the buried headers degrades system operation or if sufficient general corrosion occurs, a gross rupture or collapse of the piping sections could occur. This finding was assigned to the Mitigating System Cornerstone because the affected headers were in the SW system (mitigating system) and the finding affected the Mitigating System Cornerstone objective of equipment reliability. The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Appendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determined that the finding screened as Green because it was not a design issue resulting in loss of function per GL 91-18, did not represent an actual loss of a system=s safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation.

Enforcement:

Title 10 CFR 50.55a(g)(4) requires, in part, that throughout the service life of a boiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2, and 3 must meet requirements of Section XI.Section XI, IWA-5244, ABuried Components,@ required A(a) In nonredundant systems where buried components are isolable by means of valves, the visual examination VT-2 shall consist of a leakage test that determines the rate of pressure loss. Alternatively, the test may determine the change in flow between the ends of the buried components...@ or A(b) In redundant systems where buried components are nonisolable, the visual examination VT-2 shall consist of a test that determines the change in flow between ends of the buried components.@

Title 10 CFR 50.55a(g)(5)(iv) requires, in part, where an examination required by the Code or Addenda is determined to be impractical by the licensee and is not included in the revised ISI Program as permitted by paragraph (g)(4) of this section, the basis for this determination must be demonstrated to the satisfaction of the commission not later than 12 months after and each subsequent 120-month period of operation during which the examination is determined to be impractical.

Contrary to these requirements, as of July 1, 2004, the licensee failed to perform the pressure drop or change in flow rate testing required on the buried portions of the 31-inch SW system headers. Additionally, as of June 30, 2003, which was 12 months afte r the third 120-m onth C ode IS I interval end date, the licensee had not submitted to the N RC the b asis for considering this testing im practical. However, because of the very low safety significance of this finding and because the issue was entered into the licensee=s corrective action program (CAPs 057866, 057789, 057701), it is being treated as an NCV, consistent with Section VI.A.1 of the Enforcement Policy (NC V 05000266/20 04004-01; NCV 05000301/200 4004-01).

b.1.2 Lack of Service W ater Headers Testing During Current Code Interval

Description:

On July 1, 2004, the inspectors identified that the licensee did not intend to perform a pressure drop test or change in flow rate test to confirm the integrity of the buried SW system headers during the current 120-month Code ISI interval that started on July 1, 2002. For this Code ISI interval, the licensee was committed to follow the requirements of the 1998 Edition through 2000 Addenda of the ASME Code of Se ction XI. W ith respect to this Code E dition, the licensee stated that APressure testing of the SW system is performed on a 40 month interval; however, due to the installed and licensed configuration of the plant, it is not prudent to suspend flow to perform a pressure drop test. In addition, it is not likely that the header sectionalizing valve s would be sufficiently leak-tight to obtain valid test results using a pressure drop method.@

Further, the licensee stated, AThere is an insufficient length of stra ight upstream piping in which to install flow instrum entation with the accuracy and precision necessary to obtain valid flow test results. Even the downstream flow instrumentation that is installed (which does have adequate straight runs upstream and downstream) has an uncertainty of approximately 300gpm. Based upon these considerations, the piping cannot be considered isolable to the extent necessary to perform valid testing per IW A-5 244(b)(1).

IW A-5244(b)(2) requires that the system pressure test for non-isolable buried components shall consist of a test to confirm that flow during operation is not im paired.

The freq uent perfo rmance of IT -7A through F verifies that flow through the piping is in fact unimpaired...@

The inspectors noted that each of the buried SW headers is surrounded by butterfly type isolation valves; therefore, the inspectors concluded that the requirements of the 1998 Edition 2000 Addenda of Section XI, Article IW A-5244(b)(1) were applicable. The licensee=s basis for concluding that the buried section of SW pipe was nonisolable appeared to be a justification fo r deviation fro m the 1998 Se ction XI AS ME Co de Article IW A-5244(b)(1) requirements. Further, the licensee did not propose corrective actions to perform flow testing or pressure drop testing that was required under the previous ASME Code Section XI requirements.

Pa rt 9900 of th e N RC Inspection M anual would normally require the inspectors to submit the licensee=s position on a disputed Code requirement to the Office of Nuclear Reactor Regulation (NRR) for review. In this case, the licensee staff stated the intent to discuss the application of the 1998 Code requirements for testing of buried SW piping in a relief request submittal to justify not meeting the 1986 Edition of Section XI requirements. The inspectors confirmed with NR R s taff that the scope of a re lief request review for th is topic would include the licensee=s application of curre nt C ode requirem ents in this area.

Therefore, the inspectors considered the issue of application of current Code requirements for buried SW piping addressed by the licensee=s planned co rrective actions, which included submitting a Code relief request on the impracticality of testing the b uried SW system headers (CA P 057866).

b.2 Non-Code Repair Performed on Unit 1 Service W ater Valve SW 0322

Introduction:

The inspectors identified an NCV of 10 CFR 50.55a(g)(4) having very low safety significance (Green) for failure to conduct non-destructive examinations and repair of valve S W 0322 in accordance with the AS ME Co de Se ction XI requirements.

Description:

The licensee performed weld repairs (reference work order No. 9709004)to erosion cavities identified inside the valve body of SW 0322, which is the outlet isolation/throttle valve to c om ponent co oling water he at exchanger 12A. T he inspectors identified that the licensee had failed to perform nondestructive examinations and implement a weld repair process in accordance with Section XI of the ASME Code.

In August of 199 7, the licensee adde d weld metal to ten eros ion cavities inside the valve body of SW 0322 to restore minimum wall thickness. The final acceptance was recorded as a visual examination to verify Aoriginal contour@ and a system leakage test.

On July 1, 2004, the inspectors identified that the licensee had not perfo rmed liquid penetrant or magnetic particle examinations of the repair cavity surfaces to verify the indications were reduced to an acceptable size in accordance with requirements of Article IW D-4200(b)(1 ) of th e 1986 E dition of Section XI. T he licensee documented this non-compliance in CAP 057711 and concluded that valve SW 0322 was operable based on annual thickness measurements and no noted problems with valve performance.

The inspectors also identified that the licensee had not performed the weld repair in accordance the Owners Design Specification and original Construction Code or Se ction III as required by Article IW A-4 120 of Section XI. T he licensee documented in the Code repair replacement form No. 97-0050, that USAS B16.5, BECH 6118-M-85 and Section XI (1986 Edition) were used for the repair of this valve. However, the licensee had not followed Section XI repair methods (e.g., half bead weld technique) and the other docum ents refere nced did not contain any guidance on welded repairs.

Subsequently, the licensee identified that the vendor drawing (W illiam Powell drawing No. 059960) for the valve identified ASTM A-216 as the applicable specification for the weld repairs made on the body of this valve. ASTM A-216 required post weld heat treatments for weld repairs exceeding 20 percent of the wall thickness. The licensee had not performed a post weld heat treatment for these repairs, which exceeded 20 percent of the wall thickness and documented the failure to perform the required heat treatments in CAP 057799. The inspectors also identified that the weld procedure used for this repair may no t be a ppropriate in that the weld m etal applied by procedure (WPS-1) was potentially weaker than the minimum tensile strength required for ASTM A-2 16 Grade W CB , which required a minim um of 70,000 psi tensile strength.

Specifically, in a weld m etal tensile test reco rded in p rocedure qualification report No. 34, specimen A-2 failed in the weld metal at 69,750 psi, which is less than the minimum tensile strength required for ASTM A-216 grade W CB. The licensee entered this issue into CAP 057911 and concluded that valve SW 0322 was operable because of long acceptable service and the lack of flaws detected during ultrasonic thickness measurem ents.

An alysis: The inspectors determined that the failure to perform the required nondestructive examinations and implement a repair in accordance with Section XI of the AS ME Co de was a performance deficiency warran ting a significance evaluation.

The inspectors concluded that the finding was greater than m inor in accordance with IMC 0612, APower Reactor Inspections Reports,@ Ap pendix B, AIssue Disposition Screening,@ because, if left uncorrected, the failure to perform the required surface exam inations could have allowed unacceptable base metal flaws to rem ain in-service.

The licensee=s failure to fo llow heat treatm ents in AS TM A -216 fo r the weld repairs could result in high welding residual stresses and untem pered martensite formation.

Untempered martensite is a hard brittle phase of steel (e.g., not flaw tolerant) and can serve to allow rapid crack propagation that could jeopardize the pressure retaining function of the valve body. This finding was assigned to the Mitigating System Cornerstone because the affected valve was in the SW system (mitigating system) and the finding affected the Mitigating S ystem Co rnerstone objective o f eq uipment reliability.

The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Ap pendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determined that the finding screened as Green because it was not a design issue resulting in loss of function per GL 91-18, did not represent an actual loss of a system=s safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation.

Enforcement:

Title10 C FR 50.55a(g)(4) requires, in part, that throughou t the service life of a boiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2 and 3 must meet requirements of Section XI.Section XI, Article IW D-4200(b)(1) required AAfter final grinding, the affected surfaces, including surfaces of cavities prepared for welding, shall be examined by magnetic particle or liquid penetrant method to ensure that the indication has been reduced to an acceptable limit in accordance with IW A-3000.@ Article IW A-4 120(a) of S ection XI required, ARe pairs shall be performed in accordance with the Owners Design Specification and the original Construction Code of the component or system.@ The applicable specification for the material repaired was AST M A -216 and Pa ragraph 10.2 required, in part, AW eld re pairs shall be inspected to the same quality standards that are used to inspect the castings@

and P aragraph 10.3 required in part, ACastings containing any repair weld that exceeds 20 percent of the wall thickness or 1 inch, whichever is smaller, or ... shall be stress relieved or heat-treated after welding. This mandatory stress relief or heat treatment shall be in accordance with the procedure qualification used.@

Contrary to these requirements, on July 1, 2004, inspectors identified that in August of 1997 (reference work order N o. 9709004), the licensee performed welded repairs to valve SW 0322 and failed to perform magnetic particle or liquid penetrant examinations after final grinding and failed to perform post weld stress relief or heat treatments for repair cavities that exceeded 20 percent of the wall thickness. However, because of the very low safety significance of this finding and because the issue was entered into the licensee=s corrective action program (CAP 057711 and CAP 057877), it is being treated as an NCV, consistent with Section VI.A.1 of the Enforcement Policy (NCV 05000266/200 4004-02).

b.3 Pump Discharge Check Valves Improperly Exempted From The Code Re pair/Re placement Re quirem ents

Introduction:

The inspectors identified an NCV of 10 CFR 50.55a(g)(4) having very low safety significance (Green) for failure to implement the ASME Code Section XI examination and repair requirements for SW pump discharge check valves SW 32C and SW 32F.

Description:

On July 13, 2004, the inspectors identified a concern related to exemption of th e S W pump discharge check va lves from the AS ME Co de Se ction XI repair requirements. The licensee concluded in a number of work orders (beginning in 1990)perform ed on each of the SW pump discharge check valves tha t the valve disks were exempt from the A SM E C ode Section XI repa ir requirements. In licensee procedure NP 7.2.5, ARepair/Replacement Program,@ the licensee exempted valve disks from the repair/replacement prog ram unless they were part of a Co de Class b oundary. Ho wever, the inspectors noted that S ection XI, Article IW D-1100, AScope,@ stated, in part, that Code inspection, repair and replacement rules applied to Class 3 pressure retaining components. Further,Section III, Article ND-2110, defined pressure retaining material and this definition included valve disks. Therefore, the inspectors concluded that the pump discharge check valve disks should be considered Class 3 pressure retaining components because they have a safety function to close and retain SW system pressure for any non-running SW pump. The licensee subsequently contacted five other nuclear plants that considered these valves to be under the ASME Code repair/replacement requirements. The license also identified a memorandum from the form er C hair of th e A SM E R epair/R eplacem ent Co mmittee, which recom mended that a valve d isk be considered as a pressure boundary m aterial unless proven otherwise.

Based upon this information, the licensee staff agreed with the inspectors and initiated CAP 05 7903 to track this issue. Consequently, the inspectors identified repairs to check valve disks on valves SW 32C and SW 32F for which the licensee had not implemented Code repair requirements.

On April 17, 2003, in work order No. 9938090, the licensee weld repaired six pitted areas on the check valve disk for SW pump discharge check valve SW 32F. For two of these six re pair areas, the licensee ground out in excess of 2 0 percent of th e disk wall thickness. O n D ecem ber 3, 2003, in work order No. 0304633, the licensee weld repaired se ven pitted areas on the check valve disk for SW pum p discha rge che ck valve SW 32C. For five of these seven repair areas, the licensee ground out in excess of 20 percent of the d isk wall thickness. T he licensee docum ented in thes e work orders that these repairs were exempt fro m the Co de repair/replacement requirements and did not perform the repairs in accordance with a Code or standard. The inspectors noted that if the licensee had implemented the AST M A-216 material standard to which these valve disks were originally made, a post weld heat treatment would have been required following these repairs. Because the licensee had not perfo rmed the weld repair in accordance the Owners Design Specification and original Construction Code or Section III, they were in violation of Article IW A-4120 of Section XI. Additionally, the licensee had not performed liquid penetrant or magnetic particle examinations of the repair cavities nor documented the method of cavity me asurement in accordance with Section XI, Article IW D-4200(b)(1) and Article IW A-4130(a)(2). The licensee documented this issue in CAP 057903 and considered these valves operable based upon passing their quarterly surveillance tests.

An alysis: The inspectors determined that the failure to properly classify the SW pump discharge check valves SW 32C and S W 32F as pressure boundary material was a performance deficiency warranting a significance evaluation. Consequently, the licensee failed to perform the nondestructive examinations and repair requirements from Section XI of the ASME Code. The inspectors concluded that this finding was greater than m inor in accordance with IMC 0612, APower Reactor Inspections Reports,@

Ap pendix B, AIssue Disposition Screening,@ because, if left un corrected, the failure to perform the required surface examinations could have allowed unacceptable base metal flaws to remain in service. The licensee=s failure to select and follow a repair Code may have resulted in inadequate post weld heat treatm ents for the weld repairs that could result in high welding residual stresses and untem pered martensite formation.

Untempered martensite is a hard brittle phase of steel (e.g., not flaw tolerant) and can serve to allow rapid crack propagation that could jeopardize the pressure retaining function of the valve disk. The finding was assigned to the Mitigating System Cornerstone because the affected valve was in the SW system (mitigating system) and the finding affected the Mitigating S ystem Co rnerstone objective o f eq uipment reliability.

The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Ap pendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determined that the finding screened as Green because it was not a design issue resulting in loss of function per GL 91-18, did not represent an actual loss of a system=s safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation.

Enforcement:

Title 10 C FR 50.55a(g)(4) requires, in part, that throughou t the service life of a boiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2 and 3 must meet requirements of Section XI.Section XI, Article IW D-4200(b)(1) required AAfter final grinding, the affected surfaces, including surfaces of cavities prepared for welding, shall be examined by magnetic particle or liquid penetrant method to ensure that the indication has been reduced to an acceptable limit in accordance with IW A-3000.@ Article IW A-4120(a) of Section XI required ARe pairs shall be performed in accordance with the Owners Design Specification and the original Construction Code of the component or system.A Contrary to these requirements, on July 15, 2004, inspectors identified that on April 17, 2003, in work order No. 9938090, the licensee weld repaired six pitted areas on the check valve disk for SW pump discharge check valve SW 32F and did not perform a liquid penetrant or ma gnetic particle e xam ination on repair cavities and did n ot pe rform the repair in accordance with a documented Co de or standard.

Contrary to these requirements, on July 15, 2004, inspectors identified that on December 3, 2003, in work order No. 0304633, the licensee weld repaired seven pitted areas on the check valve disk for SW pump discharge check valve SW 32C and did not perform a liquid penetrant or magnetic particle examination on repair cavities and did not perform the repair in accordance with a documented Code or standard.

However, because of the very low safety significance of this finding and because the issue was entered into the licensee=s corre ctive action program (CAP 057903), it is being treated as an NCV, consistent with Section VI.A.1 of the Enforcement Policy (NC V 05000266/20 04004-03).

b.4 Higher than Allow ed Co ndensate Storag e T ank Tem perature

Introduction:

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, ADe sign C ontrol,@ having very low safety significance (G reen), fo r failure to ensure design b ases for the m axim um Co ndensate Storag e T ank (CST ) tem perature was correctly translated into procedures and instructions. Specifically, the Main Steam Line Break (MSLB) Containment Integrity Analysis assumed a maximum value of 100EF for the temperature of the water in the CST, while operations procedures allowed a maximum of 120EF for the CST temperature.

Description:

On June 29, 2004, the inspectors identified that the daily rounds performed by the in-plant operators in accordance with PBF -2032, ATurbine Bldg Log - Unit 1,"

Revision 73, allowed a maximum of 120EF for the C ST tem perature . The inspectors requested the lice nsee to affirm that all the applicable a nalyses used a CST tem perature of 120EF or higher.

On June 30, 2004, the licensee determined that the curre nt M SL B C ontainment Integrity Analysis (Calculation Note Number CN-CRA-01-070, which became effective on November 26, 2002), assumed a maximum value of 100EF for the auxiliary feedwater (AF W ) tem perature (the water source fo r the AF W system is taken fro m the CS T and is thus equivalent to an assumption of a maximum of 100EF in the CST). Other analyses that used AFW temperature as an input (e.g., Loss of Normal Feedwater, Small Break LOCA, and AFW Pump NPS H analyses) assumed an AFW temperature of 120EF.

The licensee reviewed the daily rounds perfo rmed by the in-plant operators in accordance with PBF -2032, ATurbine Bldg Log - Unit 1," and determined that for the past year CST temperatures were well below 100EF unless procedure O I 150, ACo ndensate Storage Tank Operations,@ was in use. W hen O I 150 was performed during unit startup/shutdown operations, the CST was intentionally heated to a temperature of greater than 100EF (with a target temperature of 110EF) so tha t the steam generators (SG s) co uld b e filled with w arm water to ensure SG pressu re/tem perature limits were met when performing procedures that involve pressurizing the SG shells for system leak checks. Du ring the performance of O I 150, the A FW pumps for b oth the shutdown unit and the operating unit were aligned to the heated CST. A review determined that at various times from October 5, 2003, through October 11, 2003, the CST was heated to a temperature of greater than 100EF (with a maximum recorded value of 108EF) w ith U nit 1 in power operations and aligned to the heated C ST . Also, at various tim es from Ap ril 11, 2004, through April 16, 2004, the CST was heated to a temperature of greater than 100EF (with a maximum recorded value of 108EF) with Unit 2 in power operations and aligned to the heated C ST .

To address current operability, the licensee reviewed the most recent available CST tem perature data from June 30, 2004, and determined that C ST tem peratures were well within the bounds of the MSLB Containment Integrity Analysis of 100EF (the tem perature for CST T-24A was 56EF and the temperature for CST T-24B was 57EF).

To address the past adequacy of the current MSLB Containment Integrity Analysis, the licensee determined that the analysis assumed a containment spray (CS) temperature of 100EF, an initial containment temperature of 120EF, and an AFW temperature (i.e., CST temperature) of 100EF. T his analysis resulted in a peak containm ent pressure of 5 9.8 psig when all bounding assumptions were applied (which was within the containment design pressure of 60 psig). An informal analysis performed by W estinghouse at the time of the analysis found that if AFW (or CST) temperature were decreased by 20EF, the peak containm ent pressure could be reduced by approximately 0.2 psi. Th erefore , if the CST temperature was at the procedurally allowed maximum limit of 120EF and all rem aining bounding assum ptions applied, a peak containm ent pressure of 6 0.0 psig could have occurred. Since the actual CST temperatures never exceeded 110EF, the actual penalty for exceeding 100EF was less than 0.2 psi. Therefore, the containment design pressure of 60 psig would not have been exce eded.

Formal sensitivity analyses performed by W estinghouse at the time of the MSLB Containment Integrity Analysis found that if CS temperature (i.e., Refueling W ater Storage Tank (RW ST) temperature) were decreased by 20EF, the peak containment pressure would be reduced by approximately 0.5 psi. Also, if the initial containment temperature were decreased by 20EF, the peak containment pressure would be reduced by approximately 0.9 psi. The actual containment and RW ST temperatures during the time periods when the CST temperature was greater than 100EF, were less than the 120EF values assumed in the analysis. The containment temperatures did not exceed 100EF and the RW ST temperatures did not exceed 80EF during the time periods of elevated CST temperature. Based on the results of the sensitivity analyses and the actual plant parameters (i.e., containment and RWST temperatures) when CST temperatures exceeded 100EF, the licensee concluded that if a MSLB had occurred on the operating unit during the time periods of elevated CST temperature, that the peak containment pressure for the operating unit would not have been exceeded.

The licensee immediately placed procedure OI 150, ACondensate Storage Tank Operations,@ on administrative hold so that the procedure could not be used until the CST temperature limitation was revised to reflect analysis limits. The licensee also revised the daily operator rou nds PBF -2032, ATurbine Bldg Log - Unit 1," on July 15, 2004, to reflect the limit of 100EF for CST temperature. The licensee entered this issue into the corrective a ction program as CA P 0 57671.

An alysis: The inspectors determined that the failure to correctly translate the design bases for the maximum CST temperature into procedures and instructions was a performance deficiency warranting a significance evaluation. The inspectors determined that the finding was m ore than m inor in accordance with IMC 0612, APower Reactor Inspections Reports,@ Ap pendix B, AIssue Disposition Screening,@ because an evaluation was required to ensure that accident analysis requirements were met and the CST was heated up to greater than the maximum analysis value of 100EF during unit startup/shutdown operations with the CS T aligned to an operating unit.

The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Ap pendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determined that the finding screened as Green because it was not a design issue resulting in loss of function per GL 91-18, did not represent an actual loss of a system=s safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation.

Enforcement:

Title 10 CF R P art 50, A ppendix B , Criterion III, ADe sign C ontrol,@ requires, in part, that m easures be established to assure that applicable regulatory requirements and the design basis are correctly translated into procedures and instructions.

Contrary to this requirement, on June 30, 2004, it was identified that since November 26, 2002, the design basis for the maximum allowable value for the CST temperature was not correctly translated into procedures and instructions, in that the MSLB Containment Integrity Analysis assumed a maximum value of 100EF for the temperature of the water in the C ST , while operations procedures OI 150, ACondensate Storage Tank Operations,@ Re vision 6, and P BF -2032, ATurbine Bldg Log - Unit 1," Revision 73, allowed a maximum of 120EF for the CST temperature. In addition, during the performance of O I 150, ACondensate Storage Tank Ope rations,@ at various times during the time period of October 5, 2003, through October 11, 2003, the CST was heated to a temperature of greater than 100EF with Unit 1 in power operations and aligned to the heated CST. Also, at various times during the time period of April 11, 2004, through April 16, 2004, the CST was heated to a temperature of greater than 100EF with U nit 2 in power operations and aligned to the heated CST. The CST temperature during portions of these time periods exceeded the maximum allowable analysis limit of 100EF.

However, because this violation was of very low safety significance and because the issue was entered into the licensee=s corrective action program, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/200 4004-04; NC V 05000301/20 04004-04).

b.5 Valves Not Meeting Technical Specification Requirements for Position Verification

Introduction:

The inspectors identified an NCV of Technical Specifications (TS)having very low safety significance (G reen) fo r failing to perform the required periodic verification of th e position of a pproximately 100 valve s in the SW system flow path servicing safety-related equipment. In addition, the licensee did not verify that 12 containment isolation manual valves were closed and two pipe fittings associated with containm ent isolation were in place at the required periodic freq uency.

Description:

On June 30, 2004, the inspectors identified approximately 80 valves in the SW system flow path servicing safe ty-related equipment that were not periodically verified per TS Surveillance Re quirement (SR ) 3.7.8.1 to be in the correct po sition every 31 days while the Un its were in Mode 1, 2, 3, or 4.

As a result the licensee placed both Units 1 and 2 in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TS Surveillance Re quirement (SR 3.0.3 ) for com pletion of the TS 3.7.8

.1 su rveillance. Temporary

procedure changes were written and completed to address the valves identified. The licensee either locked the affected valves in the corre ct position or verified the valve s to be in the corre ct position.

On July 1, July 6, and July 13, 2004, additional SW and containment isolation valves were identified by the N RC and licensee which were also required to be periodically verified to be in correct position to satisfy TS SR 3.7.8.1 and TS SR 3.6.3.2. On each date, the licensee placed both Units 1 and 2 in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TS Surveillance Requirement (SR 3.0.3 ) for com pletion of the surveillance. Temporary procedure ch anges were written and completed to address the valves identified. The licensee either locked the affected valves in the corre ct position or verified the valve s to be in the corre ct position.

In the extent of condition review, the licensee identified additional discrepancies in the component cooling system valve lineup checklists 1 -CL-C C-001 and 2-C L-C C-001. T his issue was entered into the corrective action program as CAP 057700 for evaluation.

The licensee entered these issues into the corrective action program as CAP 057665, CA P 0 57700, C AP 057712, CA P 0 57765, C AP 057766, CA P 0 57787, and CA P 0 57882.

The licensee planned to perfo rm a root cause evaluation on the issue of locked valve s to investigate the issues that led to non-compliance with the TS surveillance requirements.

An alysis: Th e inspectors determ ined that the fa ilure to perfo rm TS S R 3

.7.8.1 associated with periodic ve rification of th e position of valve s in the SW system flow path

servicin g safe ty-related equipment, and fa ilure to perfo rm TS S R 3

.6.3.2 associated with

periodic verification of the closed position of containment isolation manual valves/blind flanges was a performance deficiency warranting a significance evaluation. The inspectors determined that the finding was more than minor in accordance with IMC 0612, APower Reactor Inspection Reports,@ Ap pendix B, AIssue Dispositioning Screening,@ because it was, in most part, associated with the Mitigating Systems attribute of Configuration Control, which affected the Mitigating Systems Cornerstone objective o f en suring the availability an d reliability of the S W system to respond to initiating events to prevent undesirable consequences. A potentially mispositioned valve in the safety related SW system flow path could render the affected equipment incapable of performing its required safety function.

The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Ap pendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determined that the finding screened as Green because it was not a design issue resulting in loss of function per GL 91-18, did not represent an actual loss of a system=s safety function, did not result in exceeding a TS allowed outage time, and did not affect external event mitigation.

Enforcement:

Te chnical Specification S urveillance R equirement SR 3.7.8.1 requires, in part, that each SW valve in the flow path servicing safety-related equipment, that was not locked, sealed, or otherwise secured in position, be verified in the correct position every 31 days while the Units were in Mode 1, 2, 3, or 4.

Contrary to these requirements, on various occasions from June 30, 2004 through July 13, 2004, it was identified that since November 20, 2001 (following implementation of th e Im proved T echnical Specifications per License A mendm ent Nu mber 201 fo r Unit 1 and License Amendment Number 206 for Unit 2), the licensee did not verify the position of approximately 100 valves in the SW system flow path servicing safety-related equipment tha t we re not locked, sealed, or oth erwise secured in position , every 31 days while the Units were in Mode 1, 2, 3, or 4.

Technical Specification Surveillance Requirement SR 3.6.3.2 required, in part, that each containment isolation manual valve and blind flange that was located outside containment and was not locked, sealed, or otherwise secured and was required to be closed during a ccident con ditions, be verified closed every 31 days w hile the U nits were in Mode 1, 2, 3, or 4.

Contrary to these requirements, on July 6, 2004, it was identified that since November 20, 2001 (following implementation of the Improved Technical Specifications per License Amendment Number 201 for Unit 1 and License Amendment Number 206 for U nit 2), the licensee did no t verify that 12 c ontainm ent isolation m anual valves were closed and two pipe fittings associated with containment isolation located outside containm ent were in place every 31 days while the U nits were in Mo de 1, 2, 3, or 4.

However, because this violation was of very low safety significance and because the issue was entered into the licensee=s corrective action program (CAP 057665, CAP 057700, CAP 057712, CAP 057765, CAP 057766, CAP 057787, and CAP 057882), this violation is being treated as an NCV, consistent with Section VI.A.1 of the E nforcement Policy (NC V 05000266/20 04004-05; NCV 05000301/200 4004-05).

b.6 Additional Information Needed to Determine Adequacy of Piping Anchor Design for SW Subsystem s to C ontainm ent Fan C oolers

Introduction:

The inspectors iden tified an unresolved item concerning p iping anchors that were not evaluated in detail to demonstrate compliance with the design codes associated with SW supply and return subsystem s for primary containment fan coolers (CF Cs).

Description:

The inspectors reviewed a sample of design calculations for the reroute of SW supply and return piping subsystems asso ciated with the replacement of primary CFCs. Calculations chosen for review were W E-200093, Revision 1 including Addendum B and W E-200095, Revision 2 including Addendum A.

These SW piping subsystems were evaluated by computer analysis m ethods. Separate computer models were developed for piping between modeling anchors such as containment wall penetrations, pipe anchors attached to the containment floor, and CFC heat exchanger nozzles. Due to this modeling technique, the total piping forces on each pipe anchor attached to the containment floor had reaction components from two piping models.

Pipe stresses were determined from loads and load combinations due to internal pressure, pipe system dead weight, pipe thermal expansion, seismic excitation, and hydraulic transient effects for a LOCA event coincident with a loss of offsite power (LOOP). Pipe support loads were determined from load combinations due to pipe system dead weight, pipe thermal expansion, seismic excitation, and hydraulic transient effects for a LOCA event coincident with a LOOP.

Th e original design code for thes e piping subsystem s was Un ited S tates Activities Board (USA B) B 31.1.0-1967, APower Piping.@ The design calculations used the ASME Boiler and Pressure Vessel Code,Section III, Subsection NC and ND, 1977 Edition up to and including 1978 Addenda for design acceptan ce criteria. D esign code differences were reconciled in documentation referenced in the design calculations.

As detailed on drawing P-4 38, sheet 12, the 8-inch nominal pump size (N PS ) SW supply and return lines were routed vertically through a primary containment floor penetration and an oversized, concentric 14-inch NPS pipe cap. The pipe anchor design welded the 8-inch NPS SW process pipe to the 14-inch pipe cap, and the 14-inch NPS cap was also welded to a s teel plate attached to the containment floor.

Both calculation W E-200093 for anchor HB-19-A2 and calculation WE -200095 for anchor H B-1 9-A 2 qualified the anchor design and the anchor integral attachment weld to the 8-inch pipe using engineering judgement, determining that the structural capacity of the 14-inch NPS pipe cap was equal or greater than the 8-inch SW pipe. The calculations indicated a full penetration weld attached the SW pipe to the 14-inch pipe cap. Since the piping met code acceptance criteria, the anchor=s integral weld to the pipe was qualified by comparison.

The inspectors inquired why pipe stress at the floor anchor locations were not evaluated using pipe reactions combined from two models since the anchor integral weld was subjected to pipe reaction forces from two distinct piping models. Also, drawings P-415, sheet 9 and P-438, sheet 12 indicated that the integral attachment welds may only be partial penetration groove welds, and therefore, could have less structural capacity than the 14-inch pipe cap.

The inspectors further reviewed ASME Section III, Division 1, Subsection NF, ACom ponent Supports,@ for code jurisdictional boundaries, design requirements and acceptance criteria related to integrally attached pipe supports. When applying the combined piping reactions into the 14-inch pipe cap, the inspectors determined that the engineering judgment used in the design calculations to qualify the 14-inch pipe cap and integral weld to the SW pipe was not valid. Specifically, the resultant stress in the pipe caps needed to be determined using all piping reaction forces and bending moments, not just the piping reaction moments used to calculate SW piping stress. Also, some of the piping reactions would cause localized bending stress in the 14-inch pipe caps.

Therefore, the anchor 14-inch pipe caps may not have greater structural capacity than the SW pipe. Based on the magnitude of th e piping reaction forc es determ ined in calculation WE -200093 for Unit 2 anchors HB-19-A1, HB-19-A2, HB-19-A3 and HB-19-A4, the inspectors could not verify design code compliance without a detailed evaluation of all anchor structural componen ts.

This item is considered to be unresolved pending additional information from the licensee to demonstrate that the integral piping anchor supports for SW supply and return subsystems to primary CFCs meet applicable design code requirements. The licensee has entered this issue into their corrective action system as condition report CA P 057947 (URI 05000266/20 04-06; 050 00301/20 04-06).

.3 Co mponents

a. Inspection Scope

The inspectors examined the SW and 480 Vac systems to ensure that component level attributes were satisfied. Specifically, the following attributes of the SW and 480 Vac systems were reviewed:

Equipment/Environmental Qualification: Th is attribute verifies that the equipm ent is qualified to operate under the environment in which it expected to be subjected to under normal and accident conditions. The inspectors reviewed design information, specification s, an d docum entation to en sure tha t the S W and 480 Vac co mponents w ere qualified to operate in the temperatures and radiation fields specified in the environmental qualification documentation.

Equipment Protection: This attribu te verifies that the SW and 480 Vac system s are adequately protected from natural phenomenon and other hazards, such as high energy line breaks, floods or missiles. The inspectors reviewed design information, specification s, an d docum entation to en sure tha t the S W and 480 Vac system s were adequately protected fro m those hazard s identified in the U FS AR that could impact their ability to perform their safety function.

b. Findings

b.1 Failure to Procure Electrical Equipment for an Ungrounded Electrical System

Introduction:

Th e inspectors identified an N CV of 1 0 C FR Pa rt 50, Ap pendix B, Criterion III, ADe sign C ontrol,@ having very low safety significance (Green) associated with for the licensee=s failure to adequately translate original design requirements for the 480 Vac system into specifications during procurement of new and replacement equipment. The original specifications for equipment such as motors and cables identified the intended service as suitable for a 480 Va c ungrounded system .

Specifications for replacement motors and battery chargers did not specify the intended service as an ungrounded system.

Description:

The 480 Vac system for each unit consisted of two 480 Vac load center buses supplied through separate 4160/480 Vac transformers from the redundant 4160V safety buses. The transformers are connected in a delta-delta configuration so that the 480 Vac system is ungrounded. Ungrounded systems are susceptible to overvoltage conditions resulting from a single line to ground fa ult. A solid line to ground fau lt will result in a sustained 73 percent higher voltage to ground on the ungrounded phases, while an intermittent or sputtering ground fault can cause line to ground voltages several times normal voltage on all three phases. Because of the potential for overvoltage conditions, specifications for e quipm ent such as motors, cables, and switchgear should identify that the equipment is intended for use on an ungrounded system. The original specification for P BN P safe ty-related motors, 6118-E -32, ASp ecification for E lectric Motors,@ appropriately identified the intended service condition as a 480 Vac ungrounded system . Specification PB 580 for the s afety-related service water m otors installed in 2001 did n ot co ntain this provision. S pecification P B 92 for new battery chargers installed in 1985 similarly did not contain this provision. Equipment intended for s ervice on ungrounded systems is designed to withstand the sustained higher line to ground voltages tha n can occur on grounded system s. These insulation systems are not typically provided unless the purchaser specifies an ungrounded system .

Interviews with plant personnel indicated that PBNP has experienced 480 Vac system grounds on several occasions. While the 480 Vac system was provided with ground alarms, these devices did not provide automatic protection, and did not indicate the location of the ground. Consequently, groun d faults could pe rsist for several hou rs before being located and cleared. If a ground fault occurred during an accident, the lack of the proper insulation system would increase the likelihood of secondary failures elsewhere in the 480 Vac system. The inspectors noted that some non safety-related circuits are supplied from, and remain connected to, or can be manually connected to, the safety-re lated 480 Va c system during em ergencies. A ground fa ult on a non-safe ty circuit would cause an overvoltage that would propagate to the safety-re lated supply without operation of p rotective device s to isolate the fau lt, thereby increasing the risk to safety-re lated equipm ent.

The inspectors noted that the licensee performs regular insulation checks of motors and other 480 Va c equipm ent to detect degradation of insulation, and that ground fau lts experienced to date have not resulted in secondary failures of safe ty-related equipment.

The licensee initiated CAP 057803 and reviewed maintenance records to confirm that equipment insulation was not currently in a deteriorated condition.

An alysis: The inspectors determined that the failure to correctly specify equipment for use on an ungrounded system was a performance deficiency warranting a significance determ ination. Th e inspectors determ ined that the finding was more than m inor in accordance with IMC 0 612, APower Reactor Inspection Reports,@ Ap pendix B, AIssue Dispositioning Screening,@ because the finding involved the design control attribute of the mitigating systems cornerstone and affected the mitigating systems objective of ensuring the capability of the 480 Vac system in response to initiating events to prevent undesirable consequences. Specifically, the failure to specify the proper service for safety-re lated equipm ent increases the likelihood of its fa ilure due to stresses that could occur during a postulated accident scenario.

The inspectors evaluated the finding using Inspection Manual Chapter 0609, ASignificance Determination Process,@ Ap pendix A, ASignificance Determination of Reactor Inspection Findings for At-Power Situations,@ Phase 1 screening, and determ ined that the finding was a design or qualification deficiency confirm ed not to result in loss of function per Generic Letter 91-18. Therefore, the inspectors determined that the finding was of very low safety significance (Green). The licensee initiated CAP 057803 and reviewed maintenance records to confirm that equipment insulation was not currently in a deteriorated condition.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that m easures shall be established to assure that the design basis, is corre ctly translated into specifications, drawings, procedures, and instructions. In addition, design changes, including field changes, shall be subject to design control measures comm ensurate to those applied to the original design. Contrary to these requirements, the licensee failed to specify the ungrounded service requirem ent for 480 Vac equipment procured after the original plant construction. Because this violation was of very low significance, and documented in the licensee=s corrective action program as Condition Report CAP 057803, this finding is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000266/2004004-07; NC V 05000301/20 04004-07).

4OA2 Problem Identification and Resolution

.1 Re view of C ondition R eports

a. Inspection Scope

The team reviewed a sample of SW and 480 Vac system problems that were identified by the licensee and entered into the corrective action program. The inspectors reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiven ess of corrective a ctions related to design issues. In addition, condition reports written on issues identified during the inspection were re view ed to ve rify adequate problem identification and incorporation of th e problem into the corrective a ction system.

The specific corrective action documents that were sampled and reviewed by the team are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

.2 Confirmatory Action Letter (CAL) Follow-up Items

EQ-15-011 - Bolted Fault The licensee committed to address bolted fault calculation issues. The inspectors reviewed the status of the following action steps:

Action Step 5: The licensee committed to revise the degraded grid calculations to support changing transformer tap settings as well as revise short circuit calculations based on the new tap settings. In support of these revisions, the licensee referenced these actions in LER 266/97-032-00, which also included actions to update the site one-line electrical model of the 345 kV bus down through the 480 Vac bus loads. The licensee made progress on the completion of the calculations and was on schedule to complete step 5 by the specified due date of September 30, 2004.

Action Step 12: The licensee committed to complete the procurement of the transformer tap change material by December 31, 2004. The licensee made progress on step 12 and was sche dul ed to compl ete Step 12 by Dece mbe r 15, 2004.

Action Step 16: The licensee committed to document interim progress confirming that the project was on track in accordance with the established schedule. The licensee was not scheduled to begin this step until May 9, 2005; therefore, no inf orm ati on rega rdi ng step 16 was avai lab le for revi ew.

EQ-15-012 - Manhole and Cable Vault Flooding The license committed to install a de-watering modification in Manhole 1 and Manhole 2 to elimin ate cable vault flooding.

Action Steps 8 and 9: The licensee committed to implement the de-watering equipment and establish callups to inspect and maintain the modification. The licensee completed the modification package, which included a fire protection conformance checklist, a 10 CFR 50.59 screening and review, and a plant impact checklist. The effectiveness of the installed modification will be reviewed during future CAL close out inspections.

OP-14-003 - Validate Design Basis for High Risk Systems The licensee determined that the Design Basis Documents (DBDs) needed to be updated to reflect the current plant configuration for the following high risk significant systems: AFW , SW , Fire Protection (FP), Emergency Diesel Generators, Component Cooling, 480 Vac and 13.8kV.

a.

OP-1 4-003.3: Re vise and im plement NP 7.7.3, ADesign Basis Document Creation, Revision, and Maintenance,@ and D G-G10, ADesign Basis Document W riter=s Guide,@ to support validation and streamlining of the subject DBD=s. The licensee committed to issuing NP 7.7.3 and DG-G10 by November 10, 2004.

As of July 16, 2004, the revision of NP 7.7.3 had not begun. The licensee was waiting for a contractor to complete the Validation Guideline, which will be incorporated into NP 7.7.3. The licensee informed the inspectors that the revision will be complete by the commitment due date of N ovem ber 10, 2004. A draft revision of DG-G10 was completed on July 12, 2004.

b. OP-1 4-003.4: Issue validation plan and process for performing validation, performing revisions, and identifying open items and entering them into the CAP system. The licensee committed to having a completed Validation Guideline by March 25, 2005.

As of July 16, 2004, the Validation Guideline had not been completed. The Validation Guideline will be completed by the contractor performing the validation of the AFW DBD, and then incorporated into NP 7.7.3. The inspectors noted a problem with the commitment due date of March 25, 2005. Since the revision of NP 7.7.3 is due on November 10, 2004, the Validation Guideline needs to be completed before that date in order to be included in the revision of NP 7

.7.3. The licensee informed the inspectors that the due date fo r OP-1 4-003.4 should

be changed to November 10, 2004.

c. OP-1 4-003.6.A : Complete validation for AFW , SW , and FP, perform a progress review, and validate schedule and quality of completed work. The licensee committed to completing a progress review by May 26, 2005.

As of July 16, 2004, the progress review had not been completed. The licensee informed the inspectors that a contractor would complete the AFW DBD validation by September 30, 2004, and PBNP staff would model the validation of the S W and FP D BD s after the completed AFW DB D validation. T he inspectors did not identify any issues with the progression of this action step in meeting a May 26, 2005 due date.

d. OP-1 4-003.6.B : Co mplete validation fo r AF W . Th e licensee com mitted to completing an updated and validated DBD for AFW by September 30, 2004.

As of July 16, 2004, the A FW DB D validation had not been completed. A bid specification and proposal were expected to be issued and a contract awarded the week of July 19, 2004. The inspectors were provided with a scope of the AFW DBD validation project, which was to be translated into a request for proposal. PB NP staff inform ed the inspectors that the project was on schedule for completion by the committed due date and the AFW DBD validation will focus primarily on significant changes to the AFW system.

OP-1 4-005 Va lidate and Integrate C alculations and Se tpoints The licensee determined that discrepancies existed in system calculations and that some setpoints did not have a clear and retrievable design basis.

a.

OP-1 4-005.2.D : Re vise /Up date/C reate calculations. T he licensee committed to having a copy of the signature page from each calculation within the scope of the project showing approval signatures by June 5, 2005.

As of July 16, 2004, this action step had not been completed. The calculations had been selected and were currently in the process of being reviewed. The signature pages would become available after the final revisions or validations have been completed. Since this action step was in its early stages and was due in June 2005, the inspectors did not identify any issues regarding its progression.

b.

OP-1 4-005.2.E : Final review and acceptance of the revised emergency operating procedures (EO P) s etpoint calculations. Th e licensee com mitted to providing a copy of each signature page from the revised EOP setpoint calculations showing Operations acceptance signatures by April 4, 2005.

As of July 16, 2004, this action step had not been completed. This step was a subset of step 2.d and had a start date of December 29, 2004. Therefore, no information regarding this step was available for review. Since this action step had not been scheduled to begin until December 2004, the inspectors did not identify any issues regarding its progression.

c.

OP-1 4-005.3: Identify the population of calculations subject to validation by April 8, 2004.

This action step had been completed. The licensee provided the list of 1401 calculations to the inspectors. The inspectors did not identify any issues regarding the progression of this action step. The effectiveness of the installed modification will be reviewed during future CAL close out inspections.

d.

OP-1 4-005.7: Pre pare sem i-annual progress report. The licensee committed to completing a progress report by July 2, 2004.

This action step had been completed. The licensee provided the draft and final versions of the progress report to the inspectors. The effectiveness of the installed modification will be reviewed during future CAL close out inspections.

e.

OP-1 4-005.8: Perform mid-project effectiveness review report by August 20, 2004.

As of July 16, 2004, this action step had not been completed. This step had a start date of August 16, 2004; therefore, no information regarding this step was available for review. The inspectors did not identify any issues regarding the progression of this step.

4OA6 Me etings, Including Exits

.1 Exit Meeting

The inspectors presented the inspection results to Mr. D. Koehl and other members of licensee management at the conclusion of the inspection on July 16, 2004. The inspectors determined that proprietary information was reviewed during the inspection.

The inspectors confirmed that the proprietary material had been returned to the licensee or ind icated it would b e handled in accordance with NRC policy on p roprietary information.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Brander, Maintenance Manager

T. Carter, System Engineering Manager

B. Cole, Acting NOS Manager

J. Connolly, Regulatory Affairs Manager

G. Corell, Chemistry Manager

R. D avenport, Ac ting P lant M anager (Production P lann ing M gr)

B. Dungan, Operations Manager

F. Flentje, Excellence Team /Regulatory Affairs Principal Analyst

D. Hettick, Performance Improvement Manager

R. Hopkins, Nuclear Oversight Supvr/Equip Reliability Mgr

T. Kendall, Engineering Sr Technical Advisor

D. Koehl, Site Vice President

J. Marean, Mechanical/Structural Design Engineering Supervisor

J. McCarthy, Site Director

L. Peterson, Engineering Continuous Performance Manager

T. Petrowsky, Design Engineering Manager

M. Ray, EP Manager

A. Reiff, Acting Training Manager

M. Rosseau, Electrical/I&C Design Engineering Supervisor

G. Sherwood, Engineering Programs Manager

J. Schweitzer, Engineering Director

D. Shannon, Acting Radiation Protection Manager

T. Vandenbosch, Operating Supervisor/Operations Procedures

J. Walsh, Projects Manager

Nuclear Regulatory Comm ission

R. C aniano, D eputy Director, D ivision of Reactor Sa fety

J. Lara, C hief, Electrical E ngineering Branch, Division of Reactor Safety

P. L ouden, C hief, Branch 7, D ivision of Reactor Projects

P. Krohn, Senior Resident Inspector

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000266/2004004-01 NCV Failure to Test Service W ater Headers

05000301/2004004-01 (Section 1R21.2b.1)

05000266/2004004-02 NCV Non-Code Repair to Valve SW 0322 (Section 1R21.2b.2)

05000266/2004004-03 NCV Non-Code Repair to Valve SW 32C and SW 32F (Section 1R21.2b.3)

05000266/2004004-04 NCV Failure to Correctly Translate Condensate Storage

05000301/2004004-04 Tank Temperature Limits into Procedures and Instructions (Section 1R21.2b.4)

05000266/2004004-05 NCV Failure to Periodically Verify Position of Valves in the

05000301/2004004-05 SW System (Section 1R21.2b.5)

05000266/2004004-07 NCV Failure to Translate Original Design Requirements for

05000301/2004004-07 the 480 Vac System (Section 1R21.3b)

Opened

05000266/2004004-06 URI Additional Information Needed to Determine

05000301/2004004-06 Adequacy of Piping Anchor Design for SW to CFCs (Section 1R21.2b.6)

Discussed

None.