IR 05000369/2006007

IR 05000369-06-007 and 05000370-06-07; Duke Energy Corporation; on 03/20/2006 Through 05/19/2006; McGuire Nuclear Station, Units 1 & 2

ML061740013
Person / Time
Site:	Mcguire, McGuire
Issue date:	06/22/2006
From:	Ogle C NRC/RGN-II/DRS/EB1
To:	Gordon Peterson Duke Energy Corp
References
IR-06-007
Download: ML061740013 (46)

Text

une 22, 2006

SUBJECT:

MCGUIRE NUCLEAR STATION - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000369/2006007 AND 05000370/2006007

Dear Mr. Peterson:

On April 21, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed the onsite portion of an inspection at your McGuire Nuclear Station, Units 1 and 2. The enclosed inspection report documents the inspection findings, which were discussed on April 20, 2006, with you and other members of your staff. Following completion of additional review in the Region II office and a meeting with your staff on May 19, 2006, a final exit was held by telephone with Mr. T. Harrall and other members of your staff on June 22, 2006, to provide an update on changes to the preliminary inspection findings.

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.

The report documents four NRC-identified findings of very low safety significance (Green).

These findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they had been entered into your corrective action program, the NRC is treating these issues as non-cited violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these non-cited violations you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the McGuire Nuclear Station.

DEC 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Charles R. Ogle, Chief, Engineering Branch 1 Division of Reactor Projects Docket Nos.: 50-369, 50-370 License Nos.: NPF-9, NPF-17

Enclosure:

NRC Inspection Report 05000369/2006007 and 05000370/2006007 w/Attachment - Supplemental Information

REGION II==

Docket Nos.: 50-369, 50-370 License Nos.: NPF-9, NPF-17 Report Nos.: 05000369/2006007, 05000370/2006007 Licensee: Duke Energy Corporation Facility: McGuire Nuclear Station, Units 1 and 2 Location: 12700 Hagers Ferry Road Huntersville, NC 28078 Dates: March 20, 2006 through May 19, 2006 Inspectors: M. Thomas, Lead Inspector K. Harper, Reactor Inspector/NSPDP J. Leivo, Contractor J. Polickoski, Project Engineer J. Quinones, Reactor Inspector/NSPDP M. Shlyamberg, Contractor Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety

SUMMARY OF FINDINGS

IR05000369/2006007, IR05000370/2006007; 03/20/2006 - 03/24/2006, 04/03/2006 -

04/07/2006, 04/17/2006 - 04/21/2006, 05/19/2006; McGuire Nuclear Station, Units 1 and 2;

Component Design Bases.

This inspection was conducted by a team of four NRC inspectors from the Region II office and two NRC contract inspectors. Four Green findings, which were non-cited violations, were identified during this inspection. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP).

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The 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.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III,

Design Control. The licensee did not account for emergency diesel generator under-frequency in test acceptance criterion for ASME Section XI testing of the high head safety injection (NV) pumps 1A and 1B. The licensee entered this issue into the corrective action program and performed an operability assessment which determined that the pumps were operable.

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance because although the NV pump acceptance criteria were not conservative with respect to the safety analyses, these analyses had sufficient margin to compensate for the reduced pump performance if operated at the reduced-frequency. (Section 1R21.2.1.5)

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III,

Design Control. The licensee did not evaluate the impact of leakage past the pressure isolation check valves during low head safety injection (ND) pump operation in minimum flow (for a pump test or during a small break loss of coolant accident (SBLOCA)), in determining the maximum differential pressure (dP) across the containment sump isolation motor operated valves (MOVs). This leakage could potentially increase pressure which may challenge the capability of these MOVs to open following a SBLOCA. The licensee entered this finding into the corrective action program with an action to implement a modification to install ND suction relief valves on both units to address long term operability.

iii

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was determined to be of very low safety significance because the analysis of additional test data showed that the maximum dP at the containment sump isolation valves was less than the thrust capability of the valve actuators. (Section 1R21.2.1.6)

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III,

Design Control. The licensee did not evaluate potential failure of the non-safety related valve positioner in the safety related nuclear service water valves, and the impact of the failure on the capability of the valves to perform their design function following a seismic event. The licensee entered this issue into the corrective action program with actions to pursue a long term engineering resolution.

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because the design/qualification deficiency would not result in a loss of function. The licensee determined that adequate loads existed to prevent damage to both nuclear service water pumps if the corresponding flow control valves were to fail closed. The nuclear service water pump vendor provided documentation which indicated that the pumps could satisfactorily operate at flow rates below the minimum flow value for up to two hours without sustaining damage, which was considered adequate time to detect and respond to the problem before pump damage occurred. (Section 1R21.2.1.12)

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III,

Design Control. The licensee did not perform an analysis or use other means to demonstrate that the non-safety related nuclear service water system piping inside containment, which was credited in emergency procedures for post-accident mitigation, was qualified for the elevated temperatures predicted for a loss of coolant accident or main steam line break inside containment. The licensee entered this issue into the corrective action program with actions to revise the affected procedures and evaluate the affected systems.

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because the design deficiency did not result in an actual loss of function. The non-safety related portion of the nuclear service water system is designed to isolate on a loss of coolant accident signal. Post-accident realignment of the system would be required in order to create the scenario where the piping could be exposed to the potentially elevated temperatures/pressures. (Section 1R21.2.1.14)iv

Licensee-Identified Violations

None v

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the licensees Probabilistic Risk Assessment (PRA). In general, this included components and operator actions that had a risk achievement worth factor greater than 1.05 or a Birnbaum value greater than 1E-6. The components selected were associated with emergency core cooling system (ECCS) operation, safety-related cooling water/ventilation, and vital electrical distribution systems, as well as components required for the recirculation phase of ECCS. The operator actions were selected from the list of risk significant, time critical, operator actions. The sample selection included 17 components, five operator actions, and seven operating experience items.

Additionally, the team reviewed six modifications/10 CFR 50.59 evaluations by performing activities identified in IP 71111.17, Permanent Plant Modifications, Section 02.02.a. and IP 71111.02, Evaluations of Changes, Tests, or Experiments.

The team performed a margin assessment and detailed review of the selected risk-significant components and operator actions to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions due to modification, or margin reductions identified as a result of material condition issues. In addition, the licensees Design Margin Issues Lists were used to provide additional insights into identifying low margin equipment. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results, significant corrective action, repeated maintenance, Maintenance Rule (a)1 status, Generic Letter (GL) 91-18 conditions, NRC resident inspector input, system health reports, industry operating experience and licensee problem equipment lists. The margin assessment also considered the quality of operating procedures to meet the plant design bases, training to support those procedures, and the operator performance capability to complete the identified time critical actions within those procedures.

Operator and/or procedural reliability issues were also considered in the selection of operator actions for detailed review. These items included operator time critical task verification tests, job performance measures, problem investigative process reports, observed and logged simulator training sessions, and system walk-downs.

Consideration was also given to the uniqueness and complexity of the design, operating procedures, conditions under which the procedures would be performed, operating experience, and the available defense in depth margins.

An overall summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report. A specific list of documents reviewed is included in the attachment to this report.

.2.1.1 Residual Heat Removal (Low Head Safety Injection) Pumps/Motors/Circuit Breakers

a. Inspection Scope

This component group included the residual heat removal/low head safety injection (ND)

Pump 1A, its associated pump motor, and four kilovolt (KV) circuit breaker. The team reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), and design basis documentation (DBD) to identify and verify implementation of design requirements related to flow, developed head, net positive suction head (NPSH),vortex formation, minimum flow, shutoff head and runout protection. Design calculations, periodic test procedures (PT), and test results were reviewed to verify that the ND pump design and licensing performance requirements were met for the various operating configurations, including the high pressure recirculation (piggyback)configuration in which the ND pumps provide flow to the suction of the charging/high head safety injection (NV) pumps. Maintenance work orders (WO), in-service testing (IST), problem investigation process (PIP) corrective actions, completed PTs, and design change history were reviewed for ND Pumps 1A and 1B to assess potential component degradation and impact on design margins or performance. The team reviewed the pump installation and periodic maintenance data, as well as pump bearing and room temperature trending information, to verify consistency with vendor recommendations.

The team reviewed the licensees calculations that determined the minimum voltages at ND Pump 1A motor terminals for design basis conditions. The team also reviewed the licensees calculations that established the device settings for protection of the motor, to verify that premature trips would be precluded under design basis conditions, without unduly compromising motor protection. This included review of available power supply under worst case conditions, brake horsepower requirements for the pump motor, and ampacity calculations for the pump motor cables. The team reviewed the installation, preventive, and corrective maintenance procedures for medium voltage circuit breakers.

These procedures were compared to the vendor manual to verify consistency with vendor recommendations. The team performed a walkdown of selected four kilovolt (KV) circuit breakers to inspect the material and environmental conditions. In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated circuit breaker types to assess the failure history and operating experience over the past five years.

b. Findings

Introduction:

The team identified an unresolved item (URI) for failure to follow procedures during performance of a TS required PT for ND pump 1B. Specifically, steps in completed procedure PT/1/A/4204/001B were signed by an individual that was not qualified to sign the steps, the individual signed steps as completed which were not performed, and the individual designated a non-conditional step as being not applicable (N/A). This item is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures.

Description:

The team reviewed completed Procedure PT/1/A/4204/001B, 1B ND Pump Performance Test, which was performed on October 2, 2005. During review of this procedure, the team noted that PT/1/A/4204/001B had been performed earlier in the outage and there had been unexpected results regarding the ND pump discharge pressure. In order to eliminate the ND pump as the source of the discrepancy, the procedure was performed again per WO 98452637, to declare the pump operable. The team reviewed this completed surveillance and questioned some of the data recorded regarding pump discharge temperatures. The questions arose because the data recorded would have been different if certain procedural steps had been performed as indicated. After further review and discussions with licensee personnel, the inspectors determined that the steps had been signed as completed when they had not actually been performed. Step 12.11 had been initialed as complete, but the task was not performed. Licensee procedure OMP 4-1, Use of Operating and Periodic Test Procedures, Revision 28, required procedure users to initial or check each step after the action was completed.

The inspectors also noted that Procedure PT/1/A/4204/001B called for the determination of ND Pump 1B discharge check valve position in Step 12.35. This step is a non-conditional task, but was signed and labeled as N/A, with no documentation of approval.

Procedure OMP 4-1 stated that procedure users shall not N/A any non-conditional step, unless approved.

In addition, Steps 8.2 through 8.6 of the procedure required the initials of a licensed Reactor Operator (RO). The individual performing the PT was not a licensed RO.

Hence, the individual initialed Steps 8.2 through 8.6 as being completed, but was not qualified to do so. Procedure OMP 4-1 stated that procedure users shall be qualified to perform the task.

The licensee initiated PIP M-06-1462 to address the procedural adherence issues identified by the team. The team determined that these lack of procedural adherence deficiencies did not adversely affect the test results or the acceptance criteria for PT/1/A/4204/001B.

Analysis:

Failure to follow procedures PT/1/A/4204/001B and OMP 4-1 is a performance deficiency. This finding is related to the procedure quality attribute of the mitigating systems cornerstone and affects the objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The failure to follow procedures did not affect the pump performance during the periodic test and there was no actual loss of safety function.

Enforcement:

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Procedure OMP 4-1, Use of Operating and Periodic Test Procedures, Revision 28 stated that procedure users shall be qualified to perform the task, initial or check each step after the action is completed, and shall not N/A any non-conditional step, unless approved.

Contrary to the above, during the performance of PT/1/A/4204/001B, 1B ND Pump Performance Test, Revision 72, on October 2, 2005, the procedure user signed certain steps without having the appropriate qualifications, initialed steps as being completed that were not performed, and marked N/A on a non-conditional step without documented approval. This condition has existed since October 2, 2005. The licensee entered this item into the corrective action program as PIP M-06-1462. This finding is identified as URI 05000369/2006007-01, Failure to Follow Procedure During ND Pump 1B Performance Test. This finding is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures.

.2.1.2 Component Cooling (KC) Pump/Motor/Circuit Breaker

a. Inspection Scope

This component group included KC Pump 1A1, its associated pump motor, and four KV circuit breaker. The team reviewed the UFSAR, TS, and DBD to identify and verify implementation of design requirements related to flow, developed head, NPSH, minimum flow, shutoff head and runout protection. Design calculations, PTs, and test results were reviewed to verify that KC Pump 1A1 design and licensing performance requirements were met for the various operating configurations. Maintenance WOs, IST, PIPs, and design change history were reviewed to assess potential component degradation and impact on design margins or performance. The team reviewed KC Pump 1A1 installation and periodic maintenance procedures to verify consistency with vendor recommendations.

In addition, the team reviewed the licensees calculations that determined the minimum voltages at KC Pump 1A1 motor terminals for design basis conditions. The team also reviewed the licensees calculations that established the device settings for protection of the motor to confirm that premature trips would be precluded under design basis conditions, without unduly compromising motor protection. The team reviewed the installation, preventive, and corrective maintenance procedures for medium voltage circuit breakers. These procedures were compared to the vendor manual to verify consistency with vendor recommendations. The team performed a partial system walk-down of the four KV breakers to inspect the material and environmental conditions. In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated circuit breaker types to assess the failure history and operating experience over the past five years.

b. Findings

No findings of significance were identified.

.2.1.3 Refueling Water Storage Tank (FWST) Supply Check Valve to ND Pumps

a. Inspection Scope

The team reviewed the design, installed orientation, PT procedures and results, WOs, and industry operating experience for FWST check valves 1(2)FW-28 to verify the licensees actions to detect material and performance degradation. PIP corrective actions and system health reports were reviewed to verify that degradation was being monitored. The team reviewed the check valve preventive maintenance program and the vendor recommendations to verify proper installation and testing requirements.

b. Findings

No findings of significance were identified.

.2.1.4 High Pressure Recirculation Motor Operated Valve (Piggyback mode)

a. Inspection Scope

The team reviewed the UFSAR, TS, DBD, calculations, vendor recommendations, and PTs for motor operated valve (MOV) 1ND-58A to verify that design assumptions had been appropriately translated into design calculations, installed configuration, procedures, and acceptance criteria. PTs and test results were reviewed to verify that process medium will be available and unimpeded during accident or event conditions and to verify that individual tests and analyses validate integrated system operation under accident conditions. The team reviewed design changes and system health reports to verify that the performance capability of the valve had not been degraded through system modifications. Applicable industry operating experience items were reviewed to verify that insights had been applied to the system and component.

The team reviewed the licensees electrical calculations that determined the minimum and maximum voltage values at the terminals of MOV 1ND-58A, and reviewed the electrical interfaces with the licensees GL 89-10 MOV sizing calculations and testing, to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs for determining the electric motor operator sizing and for establishing MOV test parameters. The team also reviewed the licensees selection of thermal overload (TOL) heaters to determine if the alarm values were appropriate for motor protection. In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated motor control center/device types to assess the failure history and operating experience over the past five years. This included a sample of PIPs and modifications involving the motor control center (MCC) devices and circuits.

b. Findings

No findings of significance were identified.

.2.1.5 Charging/High Head Safety Injection (NV) Pumps/Motors

a. Inspection Scope

The team reviewed the DBD to identify design requirements related to flow, developed head, NPSH, vortex formation, minimum flow and runout protection and motor sizing for all NV pump operating conditions and configurations. Design calculations and IST and PT documentation and test results for NV Pump 1B were reviewed to verify that all design performance requirements were met. Maintenance, IST, PIP corrective actions, and design change history were reviewed to assess the potential for component degradation and impact on design margins or performance. The team reviewed the installed NV pump flow instrumentation design, installation configuration, and calibration documentation to verify the adequacy of flow measurement used for American Society of Mechanical Engineers (ASME)Section XI testing and design flow verification.

The team reviewed the licensees calculations that determined the minimum voltages at the NV Pump 1B motor terminals for design basis conditions. The team also reviewed the calculations that established the device settings for protection of the motor to verify that premature trips would be precluded under design basis conditions, without unduly compromising motor protection. In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated circuit breaker types to assess the failure history and operating experience over the past five years.

b. Findings

Introduction:

The team identified a Green, non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control. Specifically, the licensee did not account for emergency diesel generator under-frequency in test acceptance criterion for ASME Section XI testing of the NV pumps 1A and 1B.

Description:

The team identified that acceptance criterion for the ASME Section XI testing of the NV pumps, PT/1(2)/A/4209/012 A(B), Centrifugal Charging Pump 1(2)A(B)

Head Curve Performance Test, did not account for the emergency diesel generator (EDG) allowed under-frequency variation. The team evaluation identified that the test results, when corrected for the EDG allowed under-frequency variation and other non-conservative assumptions, were less than the pump acceptance criterion.

The acceptance criterion for the NV pumps was established in the licensees calculation MCC-1552.08-0197, CNC-1552.08-00-0181, Rev. 15, Safety Injection Flows for Safety

Analysis.

This calculation was performed in support of the TS surveillance requirement (SR) for the TS 3.5.2. This calculation established the minimum acceptable performance for all ECCS pumps based on their required performance to mitigate the spectra of large and small break loss of coolant accidents (LOCA and SBLOCA). The acceptance criteria established by this calculation did not take into account the EDG under-frequency. The test results were also not corrected for the EDG under-frequency.

The EDG under-frequency value of 58.8 hertz (i.e., a 2% reduction) used in the teams evaluation was the TS limit provided in SR 3.8.1.2, Verify each DG starts from standby conditions and achieves steady state voltage $ 3740 V and # 4580 V, and frequency

$ 58.8 hertz and # 61.2 hertz. The effect of the 2% frequency reduction would result in the decrease of the pump flows by 2% and the total developed head (TDH) by 4%.

When the test results were corrected for the EDG under-frequency and instrument error, the corrected test results were below the acceptance criterion for NV Pumps 1A and 1B in the minimum flow region.

The team performed a limited extent of condition review of the effect of the EDG under-frequency on the safety injection (NI) pumps. The team reviewed the completed quarterly PT/1(2)/A/4206/001 A(B), 1(2)A(B) NI Pump Performance Test and outage PT/1(2)/A/4206/015 A(B), 1(2)A(B) Safety Injection Pump Head Curve Performance Test surveillances. The review identified that the calculation did not conservatively translate the accident performance requirements for the NI pumps. In a region from zero to about 50 gallons per minute (gpm), the acceptance criterion was not bounding for the SBLOCA required flows. Additionally, for NI Pump 2A, the corrected test results were below the accident requirements.

The licensee performed an operability assessment and initiated corrective actions to address these issues in PIP M-06-1450, Allowance for Degraded EDG Frequency for NI/NV TAC Curves and PIP M-06-1620, The Shutoff Head Portion (below ~50 gpm) of the NI TAC Curve Does Not Bound Flows Assumed in the SBLOCA Analyses. The licensees operability assessment concluded that the accident analyses had sufficient margin to account for the effects of the EDG under-frequency and the NI pump curve error.

Analysis:

Failure to establish adequate acceptance criteria for the ECCS pumps surveillance is a performance deficiency. This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because although the ECCS pumps acceptance criteria were not conservative with respect to the safety analyses, these analyses had sufficient margin to compensate for the reduced pump performance due to the under-frequency.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control states, in part, that design control measures shall be applied to items such as the delineation of acceptance criteria for inspections and tests.

Contrary to the above, on April 20, 2006, the team identified that licensee calculations which established the acceptance criteria in surveillance test procedures PT/1(2)/A/4206/001A(B) and PT/1(2)/A/4206/015A(B) did not take into account operation of the NI and NV pumps at a lower allowable EDG frequency. This violation has existed for more than 10 years. Because this finding is of very low safety significance and was entered into the licensees corrective action program as PIPs M-06-1450 and M-06-1620, it is considered an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This finding is identified as NCV 05000369, 370/2006007-02, Effect of EDG Under-Frequency not Included in ECCS Pump Test Acceptance Criteria.

.2.1.6 Containment Sump Isolation Valves

a. Inspection Scope

The team reviewed the licensees electrical calculations that determined the minimum and maximum voltage values at the terminals of containment sump isolation MOV 1NI-185A, and reviewed the electrical interfaces with the licensees GL 89-10 MOV sizing calculations and testing to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs for determining the electric motor operator sizing and for establishing MOV test parameters. The team also reviewed the licensees selection of TOL heater sizes to determine if the alarm values were appropriate for motor protection. The team reviewed elementary diagrams to confirm that the interlock circuits satisfied functional requirements with adequate redundancy, independence of redundant circuits, and that the circuits included no undetectable failure vulnerability with significant consequences. In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated MCC/device types to assess the failure history and operating experience over the past five years. This included a sample of PIPs and modifications involving the MCC devices and circuits. Test results were reviewed to verify that valve performance was being monitored to identify signs of degradation.

b. Findings

Introduction:

The team identified a Green, NCV of 10 CFR 50, Appendix B, Criterion III, Design Control. Specifically, the licensee did not evaluate the impact of leakage past the pressure isolation check valves (during ND pump operation in minimum flow for a pump test or during a SBLOCA), in determining the maximum differential pressure (dP)across the ECCS containment sump isolation MOVs 1(2)NI-184B and 1(2)NI-185A.

This leakage could potentially increase pressure which may challenge the capability of these MOVs to open following a small break loss of coolant accident (SBLOCA).

Description:

The licensee identified a condition in April 2005 where the dP across the containment sump isolation valves 1(2)NI-184B and 1(2)NI-185A valves was significantly greater than previously calculated and marginal with respect to the valves capability to open. The system has a suction crosstie, thus, a pressure increase could affect the valves for both trains. These valves are required to open to establish a recirculation path for the ECCS through the ND pumps and a recirculation path for the containment spray pumps. The licensee documented this condition in PIP M-05-2204, SBLOCA dP May Be Greater than Design dP for Sump Valves 1(2)NI-184B, -185A. The licensee observed suction pressure increases during performance of ND pump quarterly IST, which are conducted in the minimum flow system alignment. The pressure increases were not attributed to thermal effects, but were attributed to addition of water to the ND system. Since the water was non-compressible, the pressure increases were indicative of gas voids in the system. The team asked if ND suction pressure could further increase due to TS allowed leakage past the PIVs (after running the ND pumps in minimum flow during a pump test or during a SBLOCA), such that the pressure could exceed the 175 psig value which the opening capability of NI-184B and NI-185A were evaluated against. The licensee indicated that the impact of leakage past the PIVs during ND pump operation in minimum flow was not considered in determining the design basis dP across 1(2)NI-184B and 1(2)NI-185A. The licensee did not have an analysis or other documentation to demonstrate that the containment sump isolation MOVs 1(2)NI-184B and 1(2)NI-185A were capable of opening against the potentially higher dPs following a SBLOCA. The licensee initiated PIP M-06-1206 to address the questions raised by the team.

The team determined that the most likely and the largest single volume of gas was the gas trapped in the ND heat exchanger u-tubes. Based on recent test data for ND Pump 2A, the team estimated this volume to be in excess of 31 standard cubic feet of gas in each ND heat exchanger. The team reviewed information provided in PIP M-02-5370, Excessive Gas Accumulation Vented at Sump Valve 1NI-185A, which indicated that there also was a non-vented gas volume of approximately seven cubic feet at each containment sump isolation valve located between each valve and the ND pumps suction. The team determined that this volume would act as a suction accumulator. In addition to the evaluation of the maximum pressure for the SBLOCA following an ND pump test, the teams review determined that, based on current licensee programs to control minimum leakage across the PIVs, the amount of gas in the ND system u-tubes was the dominant variable controlling the suction pressure increase following an ND pump test. Although the licensee had programs to minimize the amount of gas in the ECCS, these programs did not control the gas in the u-tubes.

Subsequent to this inspection, the licensee collected additional ND pump test data for Unit 1 and Unit 2 and performed calculation MCC-1223.12-00-0026, ND Pressurization Test for PIP M-06-1206, to evaluate the impact of successive ND pump starts on ND suction pressure. The licensee determined from evaluation of the test data that the containment sump isolation valves 1(2)NI-184B and 1(2)NI-185A were currently operable with respect to ND suction pressurization. The PIP included a corrective action to implement a modification to install ND suction relief valves on both units to address long term operability of the ECCS sump isolation valves.

Analysis:

Failure to include the effect of RCS leakage past the PIV in determining the maximum dP across the ECCS containment sump isolation MOVs 1(2)NI-184B and 1(2)NI-185A is a performance deficiency. This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because the licensee determined from analysis of additional test data that the ECCS containment sump isolation valves 1(2)NI-184B and 1(2)NI-185A were currently operable with respect to ND suction pressurization. The test data showed that the maximum dP at 1(2)NI-184B and 1(2)NI-185A was below the thrust capability of the actuators.

Enforcement.

10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures be established and implemented to assure that applicable regulatory requirements and the design basis for structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to this requirement, on April 20, 2006, the team determined that the licensees analyses did not include the effect of reactor coolant system (NC) leakage past the PIVs in determining the maximum dP across the ECCS containment sump isolation MOVs 1(2)NI-184B and 1(2)NI-185A. The condition has existed since before November 1993.

Because this finding is of very low safety significance and was entered into the licensees corrective action program as PIP M-06-1206, it is identified as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This finding will be tracked as NCV 05000369,05000370/2006007-03, Maximum Differential Pressure for Containment Sump Isolation Valves.

.2.1.7 a.

Inspection Scope The team reviewed the elementary diagrams for MOV 1ND-68A, to confirm that the minimum flow interlock circuits satisfied functional requirements with adequate redundancy and independence, and that the circuits included no undetectable failure vulnerability with significant consequences. For the flow instruments used in the loops, the team also reviewed the installation detail drawings as well as the calibration procedures and the results of the last three calibrations/tests for each of the two minimum flow loops in both units 1(2) NDPS-5040, 1(2) NDPG-5041, 1(2) NDPS-5050, and 1(2) NDPG-5051, to assess the performance history.

In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for similar types of flow instruments, to assess the failure history and operating experience over the past five years. This included review of a sample of PIPs.

The team reviewed the licensees electrical calculations that determined the minimum and maximum voltage values at the terminals of MOV 1ND-68A, and reviewed the electrical interfaces with the licensees GL 89-10 sizing calculations and testing, to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs for determining the electric motor operator sizing and for establishing MOV test parameters. The team also reviewed the licensees selection of thermal overload heater sizes, to determine if the alarm values were appropriate for motor protection. The team reviewed system health reports and data compiled by the licensee for the associated MCC/device types to assess the failure history and operating experience over the past five years. This included a sample of PIPs and modifications involving the MCC devices and circuits.

b. Findings

No findings of significance were identified.

.2.1.8 Residual Heat Removal Hot Leg Suction MOV

a. Inspection Scope

The team reviewed the UFSAR, TS, DBD, calculations, periodic test procedures, and vendor recommendations for MOV 1ND-1B to verify that design assumptions had been appropriately translated into design calculations, installed configuration, acceptance criteria, and procedures. Completed test results were reviewed to verify that process medium would be available and unimpeded during shutdown or accident conditions, and to verify that individual tests and analyses validated integrated system operation under shutdown or accident conditions. The team reviewed design changes and system health reports to verify that the performance capability of the valve had not been degraded through system modifications. Applicable industry operating experience items were reviewed to verify that insights have been applied to the system and component.

b. Findings

No findings of significance were identified.

.2.1.9 Safety Injection Valve MOV

a. Inspection Scope

The team reviewed the MOV calculations for safety injection system (NI) valve 1NI-147A to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs into the determination of motor actuator setpoints and sizing. Test results, maintenance history, PIPs, and design changes were reviewed to verify valve performance was being monitored to identify degradation.

b. Findings

No findings of significance were identified.

.2.1.1 0 Safety Injection Check Valves

a. Inspection Scope

The team reviewed the design, installed orientation, and the licensees actions to monitor potential degradation of safety injection check valves 1NI-60 and 1NI-71. This included periodic in-service flow and leakage testing to demonstrate full open and closure, and leak tightness. Maintenance history, PIP corrective actions, test results, foreign material exclusion controls, and design changes were reviewed to assess the potential for material degradation and the licensees capability to identify degradation.

b. Findings

No findings of significance were identified.

.2.1.1 1 Nuclear Service Water Pumps/Motors

a. Inspection Scope

The team reviewed the design basis documentation to identify design requirements related to flow, developed head, NPSH, vortex formation, minimum flow and runout protection and motor sizing for all operating conditions and configurations for nuclear service water (RN) Pumps 1A and 1B. Design calculations and IST and PT results were reviewed to verify that all design performance requirements were met. Maintenance, IST, corrective action, and design change history were reviewed to assess the potential for component degradation and impact on design margins or performance. The team reviewed the installed RN pump flow instrumentation design, installation configuration, and calibration documentation to verify the adequacy of flow measurement used for ASME Section XI testing and design flow verification.

The team reviewed the licensees calculations that determined the minimum voltages at the motor terminals for RN Pump Motor 1A for design basis conditions. The team also reviewed the licensees calculations that established the device settings for protection of the motor, to confirm that premature trips would be precluded under design basis conditions, without unduly compromising motor protection.

In addition, using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated circuit breaker types to assess the failure history and operating experience over the past five years.

b. Findings

Introduction:

The team identified a URI related to 10 CFR 50, Appendix B, Criterion III, Design Control. Specifically, the licensee did not perform system hydraulic analyses or use other means to demonstrate that RN Pumps 1A and 1B could perform their safety function under the most limiting design basis conditions.

Description:

The team identified that the licensee did not perform system hydraulic analyses nor use other means to demonstrate that RN Pumps 1A and 1B would be able to deliver the required flows to the safety related components and heat exchangers (HX)under the limiting design basis conditions. Some of the limiting design basis conditions included: maximum allowable pump degradation; maximum number of tubes plugged in the HXs; minimum ultimate heat sink (UHS) level; and EDG under-frequency. The team also identified a lack of analysis to demonstrate that the RN pumps would be protected from cavitation under the limiting design basis conditions such as minimum allowed UHS level, EDG over-frequency, maximum RN flow, minimum HX tube plugging, etc. The team also questioned how the 60/40% mud/water assumption used to establish the heat exchanger tube plugging limits was validated. Operation of the RN pumps under the most limiting design basis conditions could have affected the systems ability to deliver the required flows to the safety related HXs, or resulted in cavitation conditions. The licensee initiated PIP M-06-1593, to address these issues.

Analysis:

Failure to perform analyses to demonstrate that RN Pumps 1A and 1B could perform their safety function under the most limiting design basis conditions is a performance deficiency. This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control states, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, the team identified on April 20, 2006, that the licensee did not perform a system hydraulic analysis or use other means to demonstrate that RN Pumps 1A and 1B could perform their safety function under the most limiting design basis conditions. This condition has existed since original plant licensing and is applicable to RN Pumps 2A and 2B also. This finding was entered into the licensees corrective action program as PIP M-06-1593 with actions to evaluate the RN system capability under limiting design basis conditions. This issue is identified as URI 05000369,05000370/2006007-04, Nuclear Service Water System Flow

Analysis.

This item is unresolved pending NRC review of the licensees analysis (when completed) for the RN system under limiting design basis conditions.

.2.1.1 2 Nuclear Service Water Flow Control Valves

a. Inspection Scope

The team reviewed the functional requirements and qualification of RN air operated valves 1RN-0089A and 1RN-190B to verify that appropriate design basis event conditions were considered. Maintenance history, PIP corrective actions, and design change history were reviewed to assess the potential for component degradation and impact on design margins or performance.

b. Findings

Introduction:

The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control. Specifically, the licensee did not evaluate the potential failure of the non-safety related valve positioners and the impact of the failure on the capability of the safety related valve to perform their design function following a seismic event. The licensee did not provide design criteria to ensure that, following a design basis seismic event, valves 1RN-0089A and 1RN-190B would not fail closed due to a spurious signal generated by the valves non-safety related and non-seismically qualified positioner.

The valves are designed to fail open to their safe flow balanced position. Closure of these valves could lead to failure of the RN pumps due to insufficient minimum flow.

Description:

Nuclear service water valves 1RN-0089A and 1RN-190B are safety related air operated modulating control valves designed to fail open. The valves have two primary safety functions. The first function is to assure a RN minimum flow path (i.e.,

2700 gpm) through RN Pumps 1A and 1B to prevent the pumps from reaching the shutoff head. The second function is to remain open in the throttled flow balance position (to regulate RN flow through the KC heat exchangers) following a design basis event. The team noted that the positioner which controls operation of these modulating control valves is not safety related and is not seismically qualified. The licensee had not evaluated the impact of the positioners failure on the valves ability to perform their design functions following a seismic event. The licensee did not provide any design measures to ensure that, following a design basis seismic event, valves 1RN-0089A and 1RN-190B would not fail closed due to a spurious signal generated by the non-safety related and non-seismically qualified positioner.

The team noted that there were no seismically qualified RN flow indications in the main control room that would aid the operators if valves 1RN-0089A or 1RN-190B failed closed. The only seismically qualified RN instrument in the control room was the pumps amperage meter, which provided an indirect means of flow indication. The team postulated that following a seismic event, a number of non seismically qualified RN lines could be broken or cracked. This could lead to a large increase in RN flow. The operators would be responding to the event (based on the emergency procedures for a seismic event) and may not have any indication that securing broken RN branch lines could lead to the RN pumps being potentially dead headed and lost as a result of the RN flow control valves going closed. The licensee indicated that the emergency procedures did not have specific guidance on acceptable minimum amperage values relative to RN flow. The team performed a limited extent of condition review and noted that non-safety related and non-seismic qualification of the valve positioners was applicable to RN flow control valves 2RN-0089A and 2RN-190B also.

The licensee initiated PIP M-06-1256, Potential Nonconformance with GDC-2 with Respect to Seismic Qualification of RN to KC HX Outlet Flow Control Valves 1(2)RN-0089A and 1(2)RN-190B, to address this issue. The licensee determined that adequate Train A loads existed to prevent RN Pump 1A damage if valve 1RN-0089A were to fail closed. RN Pump 1B would have loads below the pump minimum flow requirements if valve 1RN-190B were to fail closed. The RN pump vendor provided documentation to the licensee which indicated that the RN pumps could satisfactorily operate at flow rates below the minimum flow value of 2700 gpm for up to two hours without sustaining damage, which was considered adequate time to detect and respond to the problem before RN pump damage would occur. The PIP included actions to pursue a long term engineering resolution which would alleviate the need to rely on the operator actions in place of the qualified components to address the design basis events.

Analysis:

Failure to provide adequate design measures to ensure that the modulating nuclear service water control valves 1RN-0089A and 1RN-190B will not fail closed during a seismic event is a performance deficiency. This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because the design/qualification deficiency did not result in a loss of function per GL 91-18. The licensee determined that adequate loads existed to prevent damage to both RN pumps if the corresponding flow control valves were to fail closed. In addition, the RN pump vendor provided documentation to the licensee which indicated that the RN pumps could satisfactorily operate at flow rates below the minimum flow value of 2700 gpm for up to two hours without sustaining damage, which was considered adequate time to detect and respond to the problem before RN pump damage occurred.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. UFSAR Sections 3.2 and 9.2.2 state that RN system valves designated as safety related are designed to withstand the effects of the design basis earthquake.

Contrary to the above, on April 20, 2006, the team identified that the licensee did not provide adequate design measures to ensure that the modulating service water control valves 1RN-0089A and 1RN-190B will not fail closed during a seismic event.

Specifically, the positioners for valves 1RN-0089A and 1RN-190B are not safety related nor seismically qualified. There is no assurance that these valves will remain open following a seismic event. This condition has existed since original plant licensing and is applicable to valves 2RN-0089A and 2RN-190B also. Because this finding is of very low safety significance and was entered into the licensees corrective action program as PIP M-06-1256, it is identified as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This item will be tracked as NCV 05000369, 370/2006007-05, Valve Positioners not Analyzed for Seismic Requirements.

.2.1.1 3 Nuclear Service Water Supply B Isolation Valve

a. Inspection Scope

The team reviewed the MOV calculations for RN supply B isolation valve 0RN-9B to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs into the determination of motor actuator setpoints and sizing. Test results, maintenance history, PIPs, and design changes were reviewed to verify valve performance was being monitored to identify degradation. The team reviewed the licensees electrical calculations that determined the minimum and maximum voltage values at the terminals of valve 0RN-9B, and reviewed the electrical interfaces with the licensees GL 89-10 sizing calculations and testing, to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs for determining the electric motor operator sizing and for establishing MOV test parameters.

The team also reviewed the licensees selection of thermal overload heater sizes, to determine if the alarm values were appropriate for motor protection. Using system health reports and data compiled by the licensee, the team reviewed the plant-wide operating history for the associated MCC center/device types to assess the failure history and operating experience over the past five years. This included a sample of PIPs and modifications involving the MCC devices and circuits.

b. Findings

No findings of significance were identified.

.2.1.1 4 Nuclear Service Water Piping Inside Containment

a. Inspection Scope

The team reviewed design drawings and operating procedures to verify that functional requirements and qualification of RN system piping inside containment were considered for design basis event conditions.

b. Findings

Introduction:

The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control. The licensee did not perform an analysis or use other means to demonstrate that the non-safety related piping of the RN system inside containment, which was credited in emergency operating procedures (EP) for post-accident mitigation, was qualified for the elevated temperatures/pressures predicted for these events.

Description:

The team noted that portions of the RN system inside containment, which were shown on the flow diagrams, were non-safety related. The team questioned if this piping was qualified for the elevated temperatures/pressures that could result from a LOCA or main steam line break (MSLB) event inside containment. The team also questioned if this had been evaluated as part of the licensees response to GL 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions. The team was concerned that RN system pressure boundary integrity may not be assured if the RN piping and components inside containment were to reach temperatures/pressures beyond the analyzed/design levels. Thus, re-establishment of RN flows in accordance with accident recovery procedures may result in undesirable consequences such as potential releases which bypass the credited filtration systems and/or containment flooding. The team noted that the licensee did not perform an analysis or use other means to demonstrate that the non-safety related portions of the RN system inside containment, which were credited in plant EPs for event mitigation, were qualified for the elevated temperatures predicted for these events.

The licensee did not appear to have evaluated this issue in response to GL 96-06.

The licensee initiated PIP M-06-1381, Plant Response During a Postulated Small Break LOCA During which the Reactor Coolant Pumps May Be Used to Assist in Plant Cooldown. The licensees evaluation determined that there was no specific analysis for the piping at question at the elevated temperatures/pressures and that the EOP procedures called for use of the RN and closed KC systems for certain post-accident actions. The licensee performed an extent of condition evaluation, revised the affected procedures, and initiated corrective actions to perform analysis of the affected systems.

Analysis:

Crediting the RN system for pressure integrity in EPs for post-accident recovery, after the RN system has been potentially being exposed to conditions in excess of design limits, is a performance deficiency.

This finding is more than minor because it affected the design control attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding is of very low safety significance (Green) because the design deficiency did not result in an actual loss of function per GL 91-18. The non-safety related portion of the RN system is designed to isolate on a LOCA signal. Post-accident realignment of the RN system would be required in order to create the scenario where the RN piping could be exposed to the potentially elevated temperatures and pressures.

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control states, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, on April 20, 2006, the team identified that the licensee credited the use of RN piping in the accident recovery procedures which was not analyzed for the elevated temperatures. This condition has existed since plant licensing. Because this finding is of very low safety significance and was entered into the licensees corrective action program as PIP M-06-1381, it is identified as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy. This finding will be tracked as NCV 05000369, 370/2006007-06, Effect of Post-Accident Elevated Temperatures not Analyzed for Nuclear Service Water Piping Inside Containment.

.2.1.1 5 Diesel Generator Room Ventilation

a. Inspection Scope

The team reviewed applicable portions of UFSAR Sections 3.1 and 3.3, NRC Regulatory Guides 1.76 and 1.117, and NRC Safety Evaluation Reports (SER) for the McGuire Nuclear Station, to verify that the functional requirements and qualification of the Emergency Diesel Generator (EDG) area ventilation system were consistent with the licensing and design basis. The team walked down the EDG room, inspected the ventilation dampers, reviewed the ventilation system layout and drawings, and inspected electrical cabinets housing the EDG control circuits to assess the potential for component degradation and impact on design margins or performance during design basis events.

b. Findings

No findings of significance were identified.

.2.1.1 6 FWST Level Indication and Automatic Switchover

a. Inspection Scope

The team reviewed the design of the FWST level instrumentation and the logic circuits for automatic switch-over from the injection to the recirculation flow path for the safety injection system, initiated by low-low FWST level. The team also reviewed the basis and determination of the low alarm setpoints. This included review of the loop diagrams, elementary diagrams, schematic diagrams, and logic test procedures to confirm the independence and testability of the redundant logic circuits, and to confirm that test procedures would preclude undetectable failures of significance. This included review to confirm that the valve interlock circuits satisfied functional requirements with adequate redundancy and independence of redundant circuits, subject to single failure criteria.

The team also reviewed tank and installation drawings, instrument scaling and uncertainty calculations, and interfaces with mechanical calculations, to determine the associated margins in the existing setpoints, including allowance for vortexing or other process effects. The team reviewed calibration procedures for the instrument loops to confirm that the range, scaling, accuracy and setpoints were consistent with the design and licensing bases, including consistency with the assumptions in the uncertainty calculations. The team reviewed the past three calibration and logic test results for both units to confirm an adequate performance history, and to confirm that instrument performance degradation would be identified. The team visually inspected the Unit 2 switchover logic cabinets as well as the level transmitter configurations and outdoor enclosures for both units, to assess observable material condition, vulnerability to hazards, separation of redundant channels, and the potential for environmental effects on instrument reliability and performance. The team also reviewed the configuration and performance history for the instrumentation cables routed in underground trenches from the level transmitters to the auxiliary building, with respect to the potential for long-term flooding of the cables, and the potential for circuit degradation. The team also observed the performance and use of the FWST level instrumentation and alarms during a small break LOCA scenario performed by the licensee on the plant simulator.

b. Findings

No findings of significance were identified.

.2.1.1 7 Diesel Generator Load Sequence/Start Circuits

a. Inspection Scope

The team selectively reviewed the design of the EDG load sequence and starting circuits. Because of their comparative risk significance, the review was primarily focused on the performance of auto reset relay ED (TRB3), defeat test relay FB (DTSB),and relay FC (TRA1).

This included review of the elementary diagrams and test procedures to confirm the independence and testability of the redundant logic circuits, and to confirm that test procedures would preclude undetectable failures of significance. The team reviewed the last three test results involving these relays, for both units. In addition, the team reviewed the EDG system health reports for the last three trimesters that were associated with these relays, and discussed with the system engineer the plant-wide failure history for these relay types, based on data that the system engineer had compiled and evaluated. The team also visually inspected an EDG room to assess potential vulnerabilities of the EDG electrical auxiliaries, electrical devices, and electrical enclosures to the effects of a transient low ambient pressure condition resulting from a design basis tornado.

b. Findings

No findings of significance were identified.

.3 Review of Low Margin Operator Actions

a. Inspection Scope

The team performed a margin assessment and detailed review of a sample of risk significant, time critical operator actions. Where possible, margins were determined by the review of the assumed design basis and UFSAR response times and performance times documented by job performance measures (JPM) results within operator time critical task verification tests. For the selected operator actions, the team performed a walk through of associated EPs, Abnormal Procedures (APs), Annunciator Response Procedures (ARPs), and other operations procedures with an appropriate plant operator and operations engineers to assess operator knowledge level, adequacy of procedures, availability of special equipment when required, and the conditions under which the procedures would be performed. Detailed reviews were also conducted with risk assessment engineers, engineering safety analysts, training department leadership, and through observation and utilization of two simulator training periods to further understand and assess the procedural rationale and approach to meeting the design basis and UFSAR response and performance times. The following operator actions were reviewed:

• Operator actions in response to a failure to establish high pressure recirculation

• Operator actions in response to a failure to aggressively depressurize using steam generator power operated relief valves during small/medium break LOCAs

• Operator actions in response to a failure to initiate safe shutdown system operation in time following a loss of power and a loss of RN

• Operator actions in response to a failure to swap to the containment sump during all size LOCAs given a failure of autoswap from the FWST

• Operator actions in response to a failure to cross-tie to Unit 2 RN

b. Findings

No findings of significance were identified.

.4 Review of Industry Operating Experience

a. Inspection Scope

The team reviewed selected operating experience issues that had occurred at domestic and foreign nuclear facilities for applicability at McGuire. The team performed an independent applicability review, and issues that appeared to be applicable to McGuire were selected for a detailed review. The issues reviewed by the team included:

• Review of Water-Hammer Events, NRC IN 91-50 dated August 20, 1991

• Breaker Failed to Close on Demand due to Loose Fuse Holder Clips, 12/06/2004

• 4160V Magne-Blast Air Operated Circuit Breaker Failed to Close, 04/13/2005

• TB-04-7, Westinghouse Type DS Breaker Failure to Close on Demand, 04/14/2004

• Breaker Failed to Close for a Low Head Safety Injection Pump, 05/09/2005

• Potential for Gas Binding for High Head Safety Injection Pumps (Diablo Canyon ECCS Cross Over Pipe Voiding When Swapping Charging Pumps), 10/22/2004

• Credit for Operator Actions in Place of Automatic Operator Actions, NRC Information Notice 97-78

b. Findings

No findings of significance were identified.

.5 Review of Permanent Plant Modifications

a. Inspection Scope

The team reviewed six modifications related to the selected risk significant components and operator actions to verify that the design bases, licensing bases, and performance capability of the components and operator actions have not been degraded through these modifications. The adequacy of design and post-modification testing for these modifications was reviewed by performing activities identified in NRC Inspection Procedures (IP) 71111.17, Permanent Plant Modifications, Section 02.02.a.

Additionally, the team reviewed the modifications, procedure changes, and UFSAR changes in accordance with IP 71111.02, Evaluations of Changes, Tests, or Experiments, to verify the licensee had appropriately evaluated the modifications and procedure changes for 10 CFR 50.59 applicability. The following modifications, procedure changes, and UFSAR changes were reviewed:

• MGMM-5261, Replace Westinghouse H Series Overload Heaters with FH Series Overload Heaters

• MGMM-14119, Replace existing motor control center auxiliary contacts and wire electrical interlock circuits in parallel for valve 1ND-0058A

• MGMM-14126, Replace existing motor control center auxiliary contacts and wire electrical interlock circuits in parallel for selected important valve circuits

• MEVN-1819, Change overload size from H43 to H45 for valves 1NI184 & 1NI185

• UFSAR change 06-003, Revise UFSAR Section 6.3.2.6 (Coolant Quantity, amended 04/14/05) to incorporate certain small break LOCA events and their mitigation in support of resolution of the operable but degraded/nonconforming (OBDN) condition described in PIP M-04-5115

• 10 CFR 50.59 MNS-2006-1: EP/1&2/A/5000/ES-1.2 (Post LOCA Cooldown and Depressurization) Rev. 11, Unit 1, Rev. 10, Unit 2; EP/1&2/A/5000/ES-1.3 (Transfer to Cold Leg Recirc) Rev. 20; EP/1&2/A/5000/E-1 (Loss of Reactor or Secondary Coolant) Rev. 11, Unit 1, Rev. 9, Unit 2

b. Findings

No findings of significance were identified.

While no findings of significance were identified, extensive research, numerous personnel interviews, and detailed review were required to fully understand and analyze the identified, credible NC system break scenarios that could cause a diversion of ECCS inventory to the Incore Instrument Room during a spectrum of small break LOCAs.

This extensive evaluation involved on-site, regional, and headquarters involvement and review which included a public meeting requested by the licensee to discuss the 10 CFR 50.59 evaluations related to changes to the emergency operating procedures and UFSAR that were reviewed during the McGuire component design basis inspection. A summary of the public meeting is discussed in Section 4OA6.2 of this IR. The meeting slides are available in ADAMS (Accession No. ML061740010).

4OA6 Meetings, Including Exit

.1 Exit Meeting Summary

On April 20, 2006, the team lead presented the inspection results to Mr. G. Peterson, Site Vice President, and other members of the licensees staff. Proprietary information is not included in this inspection report. Following completion of additional review in the Region II office and a meeting with the licensees staff on May 19, 2006, a final exit was held by telephone with Mr. T. Harrall and other members of the licensees staff on June 22, 2006, to provide an update on changes to the preliminary inspection findings. The licensee acknowledged the findings.

.2 Public Meeting Summary

On May 19, 2006, a Category 1 technical information public meeting was conducted at the licensees request at the Region II Office, Sam Nunn Atlanta Federal Center, 61 Forsyth Street SW, Atlanta, Georgia, 30303-8931 in Suite 24T20. The purpose of the meeting was to discuss the 10 CFR 50.59 evaluations related to changes to the emergency operating procedures and Updated Final Safety Analysis Report that were reviewed during the McGuire component design basis inspection.

During the presentation, Mr. J. Kammer, Safety Assurance Manager, delivered the opening remarks and summarized the information provided. Mr. J. Thomas, Regulatory Compliance Manager, provided some issue background and position rationale. Mr. E.

Henshaw, Safety Analysis Senior Engineer, and Mr. M. Weiner, Operations Senior Engineer, provided a detailed technical discussion with analyses and conclusions.

A copy of the meeting presentation slides are available in ADAMS (ML ).

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Bradshaw, Superintendent, Plant Operations

S. Brown, Manager, Engineering

K. Crane, Regulatory Compliance

T. Harrall, Station Manager, McGuire Nuclear Station

E. Henshaw, Senior Engineer, Safety Analysis

J. Kammer, Manager, Safety Assurance

R. Kirk, System Engineer, Mechanical and Civil Equipment Engineering (MCE)

P. Kowalewski, Maintenance Rule Coordinator, MCE

J. Nolin, Manager, MCE

G. Peterson, Site Vice President, McGuire Nuclear Station

S. Snider, Manager, Reactor and Electrical Systems Engineering (RES)

J. Thomas, Manager, Regulatory Compliance

M. Weiner, Senior Engineer, Operations

NRC personnel

J. Brady, Senior Resident Inspector

H. Chernoff, Project Manager, NRR

H. Christensen, Deputy Director, Division of Reactor Safety, Region II

C. Ogle, Chief, Engineering Branch 1, Division of Reactor Safety, Region II

J. Stang, Project Manager, NRR

S. Walker, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000369/2006007-01 URI Failure to Follow Procedure During ND Pump 1B Performance Test (Section 1R21.2.1.1)

05000369,370/2006007-04 URI Nuclear Service Water System Flow Analysis (Section 1R21.2.1.11)

Opened and Closed

05000369,370/2006007-02 NCV Effect of EDG Under-Frequency not Included in ECCS Pump Test Acceptance Criteria (Section 1R21.2.1.5)

05000369,370/2006007-03 NCV Maximum Differential Pressure for Containment Sump Isolation Valves (Section 1R21.2.1.6)

05000369,370/2006007-05 NCV Valve Positioner not Analyzed for Seismic Requirements (Section 1R21.2.1.12)

05000369,370/2006007-06 NCV Effect of Post-Accident Elevated Temperatures not Analyzed for Nuclear Service Water Piping Inside Containment (Section 1R21.2.1.14)

Discussed

None