IR 05000272/2008007

IR 05000272-08-007, 05000311-08-007; on 07/14/2008 - 08/08/2008; Salem Nuclear Generating Station Units 1 and 2; Component Design Bases Inspection

ML082660680
Person / Time
Site:	Salem
Issue date:	09/22/2008
From:	Doerflein L Engineering Region 1 Branch 2
To:	Levis W Public Service Enterprise Group
References
IR-08-007
Download: ML082660680 (38)

Text

ber 22, 2008

SUBJECT:

SALEM NUCLEAR GENERATING STATION UNIT NOS. 1 AND 2 - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000272/2008007 AND 05000311/2008007

Dear Mr. Levis:

On August 8, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Salem Nuclear Generating Station, Units 1 and 2. The enclosed inspection report documents the results of the inspection, which were discussed on August 8, 2008, with Mr.

Robert Braun and other members of your staff.

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

In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.

The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

This report documents three NRC-identified findings which were of very low safety significance (Green). All of these findings were determined to involve violations of NRC requirements.

However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating the violations as non-cited violations (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region 1; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspectors at the Salem Nuclear Generating Station. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Records 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/

Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-272; 50-311 License No. DPR-70; DPR-75 Enclosure: Inspection Report 05000272/2008007 and 05000311/2008007 w/Attachment: Supplemental Information

SUMMARY OF FINDINGS

IR 05000272/2008007, 05000311/2008007; 07/14/2008 - 08/08/2008; Salem Nuclear

Generating Station Units 1 and 2; Component Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four NRC inspectors and two NRC contractors. Three findings of very low risk significance (Green) were identified, which were also considered to be non-cited violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The team identified a finding of very low safety significance (Green) involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had used non-conservative inputs and methodologies in calculating terminal voltages to safety related motor operated valve (MOV) motors during design basis events. Specifically, PSEG had not evaluated the effect of lower transient voltages which would exist for safety injection (SI) actuated MOVs prior to voltage recovery on the upstream 4Kv buses. PSEG entered the issue into their corrective action program and performed a review of all SI actuated valves to determine the impact on their margin to operate when considering transient voltage conditions.

The finding is more than minor because the deficiency represented reasonable doubt on the operability of several charging safety injection system valves which had minimal margin. The finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of the charging system safety function. (1R21.2.1.3)

Green.

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had not implemented measures to verify that thermal overloads (TOLs) on safety-related MOV circuits were sized properly and periodically tested to verify the adequacy of the design. PSEG entered the issue into their corrective action program, completed an operability assessment for the affected equipment and will evaluate implementing testing or bypassing the TOLs during accident conditions to verify the adequacy of the design.

ii

The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the failure to assure that TOLs would not needlessly prevent safety related valves from performing their function, could affect the ability of MOVs to respond to initiating events. The team determined the finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in a loss of safety related valve operability. (1R21.2.1.4)

Green.

The team identified a finding of very low safety significance (Green) involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had not validated a key design input regarding the assumed RHR pump operation time during a small break loss of coolant accident (SBLOCA) scenario.

This design input was used to establish a new design basis differential pressure for the Unit 2 containment sump suction valves. PSEG entered the issue into the corrective action program, completed an operability assessment for the sump valves, and will evaluate long term actions to further evaluate design margin for the valves.

The finding is more than minor because the deficiency represented reasonable doubt on the operability of the containment sump valves with respect to a SBLOCA scenario. The finding is associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance (Green) because it was a design deficiency that was confirmed not to result in a loss of containment sump suction valve operability. The finding had a cross-cutting aspect in the area of Human Performance, Resources, which requires licensees to ensure personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety. This issue is related to a design calculation not being complete in that PSEG had not verified that design inputs were conservative when establishing a revised design differential pressure for the Unit 2 containment sump suction valves. (IMC 0305, Aspect H.2(c)) (1R21.2.1.6)

Licensee-Identified Violations

None iii

REPORT DETAILS

1R21 Component Design Bases Inspection (IP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the Salem Generating Station (SGS) Probabilistic Risk Assessment (PRA) and the U. S. Nuclear Regulatory Commissions (NRC) Standardized Plant Analysis Risk (SPAR) model. Additionally, the SGS Significance Determination Process (SDP) Phase 2 Notebook, Revision 2, was referenced in the selection of potential components and operator actions for review. In general, the selection process focused on components and operator actions that had a Risk Achievement Worth (RAW)factor greater than 1.3 or a Risk Reduction Worth (RRW) factor greater than 1.005. The components selected were located within both safety related and non-safety related systems, and included a variety of components such as pumps, motor control centers, heat exchangers, generators, transformers, and valves.

The team initially compiled a list of components and operator actions based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection report (05000272,05000311/2006006) and excluded those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 15 components, four operator actions and four operating experience items. The teams evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, maintenance rule (a)(1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry operating experience. Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins. The margin review of operator actions included complexity of the action, time to complete the action, and extent of training on the action.

The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (IP) 71111.21. This inspection effort included walkdowns of selected components, interviews with operators, system engineers and design engineers, and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component, operator action, operating experience sample, and the specific inspection findings identified are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 13.8Kv-4Kv No. 23 Station Power Transformer (SPT), STAPWRXFR

a. Inspection Scope

The team inspected the 23 SPT to verify it could perform its design function as described in the Updated Final Safety Analysis Report (UFSAR). The team reviewed the system one-line diagrams, automatic load tap changer (LTC) vendor specifications, automatic LTC setpoints, control circuit calculations, nameplate data, protective relay setting calculations, and loading requirements to determine the adequacy of the transformers to supply required power to the associated 4160 Vac vital buses. The team reviewed the results of recently completed transformer preventive maintenance to verify the test results were within the allowable limits. Finally, the team interviewed system engineers and performed a visual inspection of the transformer to assess the installation configuration, material condition, and potential vulnerability of the transformer to external hazards.

b. Findings

No findings of significance were identified.

.2.1.2 Emergency Diesel Generator 2B (2DAE23-GEN2BD)

a. Inspection Scope

The team inspected the electrical portions of the 2B emergency diesel generator (EDG)and associated supply breaker to verify the adequacy of the equipment to respond to design basis events. The team reviewed energy sources used to control functions of the equipment to verify their availability and adequacy. This included the adequacy of instrumentation and alarms required to support operational decisions as required by procedures. Completed surveillance tests were also reviewed to assess EDG operation under required operating conditions. The team reviewed protection/coordination and short-circuit calculations to verify the EDG was adequately protected by protective devices during testing and emergency operation. Additionally, the team reviewed calculations and technical evaluations to verify that: 1) steady-state and transient loading were within design capabilities; 2) adequate voltage would be present to start and operate connected loads; and, 3) operation at maximum allowed frequency would be within design capabilities.

The design review included determining the bases for brake horsepower loading values used, and verifying that design bases and design assumptions had been appropriately translated into the design calculations and procedures. The EDG breaker closure and opening control logic diagrams and the 125Vdc voltage calculations were reviewed to ensure adequate voltage would be available for the control circuit components and the breaker spring charging motors. Finally, the team performed a visual walkdown of the equipment, and interviewed system and design engineers to assess the installation configuration and material condition of the EDG.

b. Findings

No findings of significance were identified.

.2.1.3 4160V Vital Bus 2B (2SWGR2BD)

a. Inspection Scope

The team inspected the 4Kv vital bus 2B to verify the adequacy of its design for postulated transient and accident conditions. The team reviewed selected calculations for the electrical distribution system load flow/voltage drop, degraded voltage protection, short-circuit, and electrical protection and coordination. This review was conducted to assess the adequacy and appropriateness of design assumptions, and to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. The team also reviewed the automatic and manual transfer schemes between alternate offsite sources and the emergency diesel generator to verify that adequate voltage was maintained for safety-related loads before, during, and after the transfers. The team reviewed bus operating procedures to determine if adequate guidance was given to the operators to ensure design basis assumptions were maintained.

Additionally, the team verified that degraded and loss of voltage relays were set in accordance with design calculations, and that associated calibration procedures were consistent with calculation assumptions. The time delay relay setpoint accuracy calculations were reviewed to determine if operability was maintained. The team reviewed preventive maintenance and testing procedures to determine if breakers were maintained in accordance with industry and vendor recommendations. The associated breaker closure and opening control logic diagrams and the 125Vdc voltage calculations were reviewed to ensure adequate voltage would be available for the control circuit components and the breaker spring charging motors. Additionally, the team performed a walkdown of portions of the safety related 4160 Vac switchgear and interviewed system and design engineers to assess the installation configuration and material condition.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had used non-conservative inputs and methodologies in calculating terminal voltages to safety related motor operated valve (MOV) motors during design basis events.

Description:

The team determined that calculation ES-15.008, Salem Units 1 & 2 Degraded Grid Study, Revision 5, which was a direct design input into applicable mechanical MOV thrust and torque calculations, non-conservatively neglected the effect of block starting MOVs, thus predicting higher voltages than would be available. The purpose of the calculation was in part to determine the voltage profiles for vital equipment during a worst case design basis event (DBE) that would still allow the offsite preferred source of power to remain in service. The team noted that individual mechanical MOV thrust and torque calculations used steady-state post transient MCC voltages associated with having 3910V at the 4Kv buses. The team determined that the use of steady-state post transient MCC voltages, instead of transient block loading voltages, to evaluate the starting terminal voltages for MOVs required to change state during a safety injection (SI) signal would predict higher terminal voltages than would actually be available. Additionally, the team noted that during the period of time during the accident transient loading, the SI actuated MOVs could be in a stall condition until the voltage at the MCC recovered. PSEG had failed to analyze the effect on MOV torque capability during the initial block loading with lower voltages available to the valve motors and had not evaluated the potential for delay in valve movement with respect to safety analysis assumptions for valve stroke timing. The team determined that PSEG had not evaluated if the associated thermal overloads for the safety related valve motors would trip during the time period that the MOVs could be in a stall condition due to the reduced voltage available.

The team also noted that calculation ES-15.006, U2 230V Vital MCC, 120V Control Power Circuit Voltage Drop Study, used steady-state post event MCC voltages to evaluate the control circuit voltage drop for the control circuits for MOVs that were required to change state for a design basis event. The use of these steady state voltages instead of transient voltages would predict higher control circuit voltages than would actually exist. As a result, the team had concerns that the control circuit contactors for the associated safety related MOVs which change state during an SI signal, may not have adequate voltage to energize until after the upstream 4.16Kv starting loads had accelerated.

Additionally, the team noted that PSEG did not have a calculation or analysis that would predict the available starting voltages to safety related MOVs required to change state for an SI signal when powered by the emergency diesel generators. The offsite power calculation ES-15.008 used 4210V as the 4Kv vital bus voltage at the pre-event assumed starting voltage. However, the EDG acceptable voltage is 3910V and therefore the dynamic transient voltage levels may not be bounded by the offsite power analyses. The team was concerned that applicable block loaded safety related MOVs would potentially have inadequate starting voltages when supplied by the EDG.

In response to the teams concerns, PSEG entered the issue into their corrective action program to reconcile the Salem MOV capability assessments with the Salem degraded grid study. PSEG performed a review of all SI actuated valves to determine the impact on their margin to operate when considering transient voltage conditions. The team reviewed PSEGs determination that a reasonable basis for operability existed for valves which were determined to fall below the 70% voltage acceptance criteria established by the MOV capability assessments. The affected valves were associated with the boron injection tank inlet and outlet valves associated with the charging safety injection system flowpath. The team concurred that a reasonable basis for operability existed when considering that parallel valves which had adequate voltage levels would actuate and reduce the differential pressure (DP) across the affected valves. The team also noted that conservative cable temperature assumptions were utilized which tend to predict larger than actual voltage drops for the valve motors. Additionally, the team independently reviewed 2B EDG voltage data during EDG load testing and determined that the offsite power calculation for minimum voltage levels bounded the test results for the 2B EDG supplying the vital 4Kv bus which supported a reasonable basis for operability with respect to starting MOV voltages when powered from an EDG.

PSEG determined that longer term corrective actions included revising ES 15.008 to define the 230 V Vital MCC load profile for the voltage transient at the start of the loss-of coolant accident (LOCA) scenario from offsite power during degraded grid conditions.

The resultant voltage predictions would then be used for MOV capability assessments.

This issue has been entered into PSEGs corrective action program as notifications

===20379126, 20378039, and 20379247.

Analysis:

The team determined that a performance deficiency existed in that non-conservative inputs and methodologies had been used during calculation of minimum terminal voltages to safety related motor operated valve (MOV) motors during design basis events. Specifically, PSEG had not evaluated the effect of lower transient voltages which would exist for SI actuated MOVs prior to voltage recovery on the upstream 4Kv buses.

The finding was more than minor because it was similar to NRC Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, Example 3.j, in that there was a reasonable doubt on the operability of several charging safety injection system valves which had minimal margin. The finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Traditional enforcement does not apply because the issue did not have any actual safety consequences or potential for impacting the NRCs regulatory function, and was not the result of any willful violation of NRC requirements. In accordance with NRC IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, a Phase 1 SDP screening was performed and determined the finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in a loss of charging system function.

Enforcement:

10 CFR, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of design.

Contrary to the above, as of August 4, 2008, measures had not been established to verify the adequacy of the design minimum voltage levels utilized in SI actuated MOV capability assessments. This resulted in nonconservative voltages being used as design inputs in the analyses of SI actuated MOVs. Because this violation is of very low safety significance and has been entered into PSEGs corrective action program (20379126, 20378039, and 20379247), it is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000272;311/2008007-01, Inadequate Design Control for MOV Capability Assessments)

Unresolved Item: The team identified an unresolved issue pertaining to the susceptibility of a design basis event concurrent with a degraded 4Kv vital bus. Specifically, PSEGs UFSAR section 8.3, Onsite Power System, states the following: The Offsite Power System in combination with the onsite distribution system has been shown by analysis and test to possess sufficient capacity and capability to automatically start and subsequently operate all safety loads within their voltage ratings for anticipated transients and accidents. The worst sustained undervoltage condition in the onsite distribution system was found to occur with a severely degraded 500 Kv offsite system simultaneous with a concurrent loss-of-coolant (LOCA) on Unit 2 and unit trip on Unit 1 (or vice versa). The team was concerned that a postulated sustained undervoltage condition may result in the degraded voltage relays (second level undervoltage protection) not having sufficient voltage to reset following the start of the postulated accident initiated loads. If this were to occur, the 4Kv vital bus voltages on all three buses could remain below the degraded voltage setpoint of 94.6% but higher than the loss-of-voltage setpoint of 70% for the duration of the degraded voltage time delay of 13 seconds nominal. Subsequently, the 4Kv vital buses would automatically disconnect from offsite power and transfer to the emergency diesel generators as designed.

However, during the 13 seconds of degraded voltage, the safety related loads may have inadequate voltages to start or run and therefore go into a stall condition that could trip their associated protective relays or thermal overload relays (TOLs). The team noted that the safety related MOV thermal overload relays are not bypassed on an accident condition for the Salem Units. After disconnection from offsite power and transfer to the EDG, any loads that tripped on their protective devices would reset and restart on the EDG with the exception of safety related MOVs or motors that have TOLs. For those loads, they would become unavailable and not restart on the EDG. The TOLs can only be reset from the affected motor control centers in order to restart the motors or MOVs.

It was not clear if this scenario is within Salems licensing basis. PSEG was researching licensing documentation in response to the question. Regardless of their licensing bases, PSEG conservatively determined to take an action relative to the potential for degraded offsite power conditions. At the time of the inspection they issued a standing order to clarify that in lieu of entering TS 3.8.1.1 action d, when both trains of offsite power are declared inoperable due to degraded voltage on the grid, they will enter TS 3.0.3. This issue was unresolved pending determination of PSEGs licensing bases.

PSEG entered the issue into their corrective action program as Notifications 20379249, 20379246, and 20379520. (URI 05000272;311/2008007-04, Vital Bus Degraded Voltage Licensing Bases)

.2.1.4 230V No. 2B West Valves and Miscellaneous Vital Control Center

a. Inspection Scope

The team inspected the 230V vital control center to verify the adequacy of its design for postulated transient and accident conditions. The team reviewed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions.

The protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst-case short-circuit conditions. Finally, the team performed a walkdown of portions of the safety-related 230V vital control center and interviewed system and design engineers to assess the installation configuration and material condition.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had not implemented measures to verify that TOLs on safety-related MOV circuits were sized properly and periodically tested.

Description:

Regulatory Guide 1.106, Thermal Overload Protection for Electric Motors On Motor-Operated Valves, Revision 1, specifies methods acceptable to the NRC staff to ensure that the thermal overload protection devices will not needlessly prevent the motor from performing its safety related function. This guide specifies alternative methods such as bypassing the TOL during a design basis event or leaving it in the circuit continuously, provided they were sized properly and periodically tested. The Salem design has left the TOLs in the MOV circuits continuously. However, the team determined that Salem had not performed appropriate analysis nor demonstrated through periodic testing that the TOLs would not inadvertently operate to prevent MOVs from performing their safety function. The team noted that PSEG had established a very conservative protection criteria that met the current industry guidelines as recommended in IEEE 741-1990, IEEE Standard Criteria for the Protection of Class 1E Power Systems and Equipment in Nuclear Power Generating Stations, for the safety related MOVs and their associated cables. However, the existing TOL sizing criteria had not ensured that the sizes selected were adequate to ensure the safety function would be met for a design basis event, which can subject the MOVs to transient voltage dips, possible stall conditions, and degraded voltage.

Salem USFAR Appendix 3A states that the Salem design satisfies the requirements of IEEE 308-1971, IEEE Standard Criteria for Class 1E Electric Systems for Nuclear Power Generating Stations. This standard was endorsed by NRC Regulatory Guide 1.32.

Section 6.3 of the standard states, in part, that tests shall be performed at scheduled intervals to demonstrate that standby power equipment and other components that are not exercised during normal operation of the station are operable. The team noted that PSEG had previously implemented corrective actions in 1995 to address concerns identified with TOL relays. PSEG had created a thermal overload trip testing procedure, SC.MD-PT.115-0001, which has since been superceded by SC.MD-PT.230-0001, Thermal Overload Relay Overcurrent Trip Testing, Rev. 5. This test states in section 1 that the thermal overload relays will be tested such that at least 10% of the total are tested once per 18 months on a rotating basis and each thermal overload relay is tested within 60 months. The team determined that PSEG has not been implementing this test in accordance with the procedural direction and therefore had not been periodically demonstrating functionality of the TOLs.

PSEG entered the issue into the corrective action program as notifications 20378945 and 20377229. PSEG determined that there is reasonable assurance that the TOLs would not prevent valves from performing their safety function. PSEG noted that all of the thermal overloads had been tested to validate proper trip setpoint times in the 1996 timeframe and a history search of the corrective action system had not identified failures of MOVs to stroke due to failures of TOLs. The team concluded that although trip point verification of TOL relays had not been periodically verified, there was reasonable assurance based on the above that safety related valves remained functional. PSEG will evaluate implementing testing or bypassing the TOLs to verify the adequacy of the design.

Analysis:

The team determined that the failure to assure that TOLs on safety related MOV circuits were sized properly and periodically tested was a performance deficiency warranting a significance evaluation. The issue was determined to be more than minor in accordance with NRC Inspection Manual Chapter 0612, Appendix B, Issue Dispositioning Screening. The finding was associated with the design control attribute of the Mitigating Systems Cornerstone objective and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the failure to assure that TOLs would not needlessly prevent safety related valves from performing their function, could affect the ability of MOVs to respond to initiating events. Traditional enforcement does not apply because the issue did not have any actual safety consequences or potential for impacting the NRCs regulatory function, and was not the result of any willful violation of NRC requirements. In accordance with NRC IMC 0609, 4, Phase 1 - Initial Screening and Characterization of Findings, a Phase 1 SDP screening was performed and determined the finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in a loss of safety related valve operability.

Enforcement:

10 CFR Part 50, Appendix B, Criterion III, Design Control, requires in part, that 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, as of August 1, 2008, PSEG had failed to ensure design control measures were in place for verifying or checking the adequacy of the design of the TOLs for safety related MOVs. PSEG failed to assure the trip setpoint of the TOLs had not changed after being in service by not implementing a periodic testing program for the TOLs. PSEG entered this issue into the corrective action program as notifications 20378945 and 20377229. Because this violation was of very low safety significance and was entered into PSEGs corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000272;311/2008007-02, Inadequate Design Control for MOV Thermal Overload Protection Devices)

=

a. Inspection Scope

The team inspected the 460V vital bus to verify the adequacy of its design for postulated transient and accident conditions. The team reviewed selected calculations for the electrical distribution system load flow/voltage drop, short circuit, and electrical protection and coordination. The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions.

The switchgears protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case short-circuit conditions. The team reviewed the voltage protection scheme and the adequacy of instrumentation/alarms available. To team reviewed the preventive maintenance inspection and testing procedures to ensure that breakers were maintained in accordance with industry and vendor recommendations. The 125 Vdc voltage calculations were reviewed to determine if adequate voltage would be available for the breaker open/close coils and spring charging motors.

The team inspected the 4Kv/460V transformer to verify it would perform its design function during design basis events. The team reviewed calculations such as load flow/voltage drop, and electrical protection and coordination to verify the adequacy of the design. The team assessed the sizing, loading, protection, and voltage taps for the transformer to ensure adequate voltage would be supplied to the 460Vac vital bus.

Additionally, the team reviewed the protective device settings to ensure that the feeder cables and transformer were protected in accordance with industry standards.

Finally, the team performed a walkdown of portions of the safety related 460Vac switchgear and 4Kv/460V transformer and interviewed system and design engineers to assess the installation configuration and material condition.

b. Findings

No findings of significance were identified.

.2.1.6 Containment Sump Suction Valve, S2SJ-22SJ44

a. Inspection Scope

The team inspected the Unit 2 containment sump suction valve, S2SJ-22SJ44, to verify that it was capable of meeting its design basis requirements. This alternating current (AC) motor-operated valve (MOV) is normally closed and has an open safety function to provide suction for the residual heat removal (RHR) pumps during the recirculation phase of a loss-of-coolant-accident (LOCA). The review included system and motor operated valve calculations to verify that the thrust and torque limits and actuator settings were correct. The team also reviewed modifications performed on the containment sump suction valve. The team interviewed engineers and reviewed correspondence related to NRC Generic Letter 95-07, Pressure Locking and Thermal Binding of Safety Related Power-Operated Gate Valves, to ensure the valve would not be susceptible to pressure locking or thermal binding phenomena. Inservice tests were reviewed to verify that the stroke time acceptance criteria were in accordance with the UFSAR and accident analysis assumptions. The team reviewed electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate. Finally, corrective action issues related to the valve were reviewed to ensure conditions did not exist which would invalidate design assumptions for the capability of the valve.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that PSEG had not validated a key design input regarding the assumed RHR pump operation time during a small break loss-of-coolant accident (SBLOCA) scenario. This design input was used to the establish a new design basis differential pressure for the containment sump suction valves.

Description:

The team reviewed containment sump suction valve calculation S-C-SJ-MDC-2124, Pressure Increase on the RHR Side of SJ44 Following a Small Break LOCA, to determine the adequacy and validity of design inputs. The calculation addressed a SBLOCA scenario in which the RHR pump starts on a safety injection signal. However, due to high reactor backpressure, the pumps do not inject into the vessel, but run on minimum flow back to the pump suction. In this scenario component cooling water (CCW) is not cooling the RHR heat exchanger, as there is no procedural direction to valve it in during the injection phase of a SBLOCA. Therefore, the water is circulating in a closed system and heating up due to RHR pump energy. The closed loop heat-up results in a pressure increase and a large pressure differential across the containment sump valve, S2SJ-22SJ44. The team noted that PSEG had recently completed a design change which modified the gear ratio to improve valve margin capability for this scenario using conservative design inputs. Based on the results of calculation S-C-SJ-MDC-2124, a system temperature increase of 19 degrees would occur in 30 minutes, corresponding to a pressure of up to 439 psig. On November 5, 2007, this calculation established a new design differential pressure for S2SJ-22SJ44 of 427 psid. Following the modification to the valve actuator gear ratio, the valve design capability margin in the opening direction was increased to a nominal 20%.

However, the team found no evidence to support that PSEG had verified or validated the design basis input assumption of securing the RHR pumps within 30 minutes in response to a postulated SBLOCA scenario. The team noted this was a critical design basis input in their calculation. Calculations or evaluations did not conclusively evaluate or verify that for different break sizes, conditions, and existing Emergency Operating Procedures (EOP) strategies that 30 minutes would not be exceeded. The team noted that the basis document for PSEG procedure, 2-EOP-FRHS-1, Response to Loss of Secondary Heat Sink, Rev. 24, described a similar system configuration scenario of an RHR pump running with reactor coolant system (RCS) pressure above the shutoff head of the pumps without component cooling water (CCW) to the RHR heat exchangers.

This procedure contained a caution to not run the pumps longer than 60 minutes without CCW to the RHR heat exchangers. Interviews with plant operators indicated they were familiar with this 60 minute limitation. However, this time limit or cautionary instruction to the operators did not support the assumption that operators would be aware of the importance of the 30 minute time limit for securing an RHR pump in a similar system configuration for events such as a small break LOCA. Additionally, the team reviewed the calculation and determined that waiting an additional 15 minutes, or 45 minutes into the event, could theoretically result in differential pressures close to the system discharge pressure relief setpoint of 600 psid.

In response to the teams concerns, PSEG entered the issue into the corrective action program as notification 20378769. PSEG evaluated the valve capability assuming the system pressure would increase to the relief valve setting of the system. PSEG determined that the valve remained operable using conservative design values for coefficient of friction and degraded voltage; however, the design margin was reduced from 20% to a nominal 1%. The team recognized that PSEGs evaluation had utilized several conservative assumptions. Specifically, PSEG assumed that all of the pumps energy was input into the water, system valves were leak tight, pump suction and discharge pressures were assumed to equalize, thermal expansion of the pipe was neglected, degraded voltage at the motor control center was assumed, and an ambient motor temperature of 175 degrees Celsius was conservatively used in PSEGs evaluation of valve margin to determine operability. The team reviewed PSEGs current operability evaluation and found it to be acceptable. The team reviewed margin capability for the valve prior to the gear change performed in the last refuel outage. The team determined that actual test data for coefficient of friction, along with realistic assumptions for other key parameters provided a reasonable basis that slight margin in the open direction had existed prior to the gear change modification. PSEG will evaluate long term actions to further evaluate design margin for the valve. The team noted this issue was not an immediate concern for the Unit 1 containment sump suction valves due to a different piping arrangement which provided for an open path to a relief valve in the suction line of the RHR pumps.

Analysis:

The team determined that the failure to verify that a key design input was conservative in establishing the design differential pressure for the containment sump valve was a performance deficiency that was reasonably within PSEGs ability to foresee and correct. Specifically, PSEG failed to validate that a design assumption of securing the RHR pumps within 30 minutes was bounding in any SBLOCA scenario.

The finding was more than minor because it was similar to NRC Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, Example 3.j, in that a key design input had not been validated or verified to be conservative for potential accident scenarios resulting in RHR pump recirculation, causing a reasonable doubt of operability for the containment sump valve. This finding is associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Traditional enforcement does not apply because the issue did not have any actual safety consequences or potential for impacting the NRCs regulatory function, and was not the result of any willful violation of NRC requirements. In accordance with NRC inspection Manual Chapter 0609, 4, Phase 1- Initial Screening and Characterization of Findings, a Phase 1 SDP screening was performed and determined the finding was of very low safety significance (Green) because it was a design deficiency that was confirmed not to result in a loss of containment sump suction valve operability.

The finding had a cross-cutting aspect in the area of Human Performance, Resources, which requires licensees to ensure personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety. This issue is related to a design calculation not being complete in that PSEG had not verified that design inputs were conservative when establishing a new design differential pressure for the Unit 2 containment sump suction valve. (IMC 0305, Aspect H.2(c)).

Enforcement:

10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures provide for verifying and checking the adequacy of design.

Contrary to the above, as of November 5, 2007, PSEG had not verified a key design input assumption established in calculation S-C-SJ-MDC-2124, which determined a new design basis differential pressure for the Unit 2 containment sump suction valve.

Specifically, the 30 minute assumed RHR pump operation time during a SBLOCA had not been validated or verified to conclusively show that the 30 minute timeframe was a conservative value and would not be exceeded. Because this violation was of very low safety significance and was entered into PSEGs corrective action program (notification 20378769), this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000311/2008007-03, Inadequate Design Control for Unit 2 Containment Sump Valve Design DP Determination)

.2.1.7 RHR Piggyback Valve, S2SJ-22SJ45

a. Inspection Scope

The team inspected the Unit 2 RHR piggyback valve, S2SJ-22SJ45, to verify that it was capable of meeting its design basis requirements. This alternating current (AC) motor-operated valve (MOV) is normally closed and has an open safety function to provide suction from RHR to the ECCS pumps during the recirculation phase of a LOCA. The review included system and motor operated valve calculations to verify that the thrust and torque limits and actuator settings were correct. The team also interviewed engineers and reviewed correspondence related to NRC Generic Letter 95-07, Pressure Locking and Thermal Binding of Safety Related Power-Operated Gate Valves, to ensure the valve would not be susceptible to pressure locking or thermal binding phenomena.

Inservice tests were reviewed to verify that the stroke time acceptance criteria were in accordance with the UFSAR and accident analysis assumptions. Additionally, condition reports related to the valve were reviewed to ensure conditions did not exist which would invalidate design assumptions for the capability of the valve. The team reviewed electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate. Finally, walkdowns of accessible areas were performed to assess the current condition of the valve.

b. Findings

No findings of significance were identified.

.2.1.8 Diesel Fuel Oil Transfer Pumps, S1DF-1DFE9/10

a. Inspection Scope

The team inspected the Unit 1 diesel fuel oil transfer pumps, S1DF-1DFE9/10, to verify their capability to perform as required during design basis accident conditions for Emergency Diesel Generator (EDG) operation. The positive displacement diesel fuel oil transfer pumps transfer fuel from the storage tanks to the diesel fuel oil day tanks. This review included various design basis documents including diesel fuel oil system calculations, technical specifications, the UFSAR, and system drawings. The team verified the capability of the Unit 1 fuel oil transfer pumps to provide their design flowrate. In addition, the team verified the basis for the pump inservice testing (IST)acceptance criteria, the basis of various setpoints associated with pump operation, and the availability of adequate net positive suction head (NPSH) during fuel oil transfer pump operation. The team observed portions of the 11 diesel fuel oil transfer pump quarterly IST on August 1, 2008, to independently assess pump performance and test control. Walkdowns of accessible areas were performed to assess the material condition of the pump. Finally, the team reviewed system health reports to determine the overall health of the system.

b. Findings

No findings of significance were identified.

.2.1.9 Unit 1 Residual Heat Removal Pump 11 (RHR), S1RHR-1RHE1

a. Inspection Scope

The team reviewed the design, testing and operation of RHR pump 11 to verify that it could perform its design function of providing required pump performance (flowrate and developed head) under operating, transient and accident conditions. The team reviewed design calculations to assess the adequacy of the design relative to net positive suction head, vortex protection, minimum flow, and runout protection and to assess the capability of the pump to achieve the flow and developed head as assumed in operating, transient and accident calculations. The team reviewed pump surveillance tests to ensure that testing was sufficient and was in accordance with plant technical specification requirements and that the results confirmed acceptable pump performance.

The team interviewed design and system engineers regarding the design, operation, testing and maintenance of the pump. The team performed a walkdown to assess the material condition of the pump.

b. Findings

No findings of significance were identified.

.2.1.1 0 Intermediate Head Safety Injection Pump 21, S2SJ-2SHE2

a. Inspection Scope

The team reviewed the design, testing and operation of the Unit 2 safety injection pump 21 to verify that it could perform its design function of providing required pump performance (flowrate and developed head) under operating, transient and accident conditions. The team reviewed design calculations to assess the adequacy of net positive suction head, vortex protection, minimum flow, and runout protection and to assess the capability of the pump to achieve the flow and developed head as assumed in operating, transient and accident calculations. The team reviewed pump surveillance tests to ensure that testing was sufficient and was in accordance with plant technical specification requirements and that the results confirmed acceptable pump performance.

The team interviewed design and system engineers regarding the design, operation, testing and maintenance of the pump. The team performed a walkdown to assess the material condition of the pump.

b. Findings

No findings of significance were identified.

.2.1.1 1 High Head Centrifugal Charging Pumps, 21 & 22, S2CVC-1CVE21,22

a. Inspection Scope

The team reviewed the design, testing and operation of the Unit 2, 21 & 22 high head centrifugal charging pumps to verify that they could perform their design function of providing required pump performance (flowrate and developed head) under operating, transient and accident conditions. The team reviewed design calculations to assess the adequacy of net positive suction head, vortex protection, minimum flow, and runout protection and to assess the capability of the pumps to achieve the flow and developed head as assumed in operating, transient and accident calculations. The team reviewed pump surveillance tests to ensure that testing was sufficient and was in accordance with plant technical specification requirements and that the results confirmed acceptable pump performance. The team interviewed design and system engineers regarding the design, operation, testing and maintenance of the pump. The team performed a walkdown to assess the material condition of the pumps.

b. Findings

No findings of significance were identified.

.2.1.1 2 Component Cooling Pump 21, S2CC-2CCE4

a. Inspection Scope

The team reviewed the design, testing and operation of the Unit 2, 21 component cooling pump to verify that it could perform its design function of providing required pump performance (flowrate and developed head) under operating, transient and accident conditions. The team reviewed design calculations to assess the adequacy of net positive suction head, vortex protection, minimum flow, and runout protection and to assess the capability of the pump to achieve the flow and developed head as assumed in operating, transient and accident calculations. The team reviewed pump surveillance tests to ensure that testing was sufficient and was in accordance with inservice test requirements and that the results confirmed acceptable pump performance. The team interviewed design and system engineers regarding the design, operation, testing and maintenance of the pump. The team performed a walkdown of the pump to assess the material condition of the pump and associated equipment.

b. Findings

No findings of significance were identified.

.2.1.1 3 Component Cooling Heat Exchanger 22, S2CC-2CCE5

a. Inspection Scope

The team reviewed the safety analysis report, design basis calculations, engineering evaluations, PSEGs Generic Letter (GL) 89-13 response, and the bio-fouling program to identify the design basis heat removal requirements for the component cooling water heat exchanger. The team reviewed test data including acceptance criteria to ensure that the required performance of the heat exchanger was consistent with performance assumptions for transient and accident conditions. The team reviewed these results to confirm that the minimum design basis heat removal capability was monitored, trended, and maintained. The team reviewed design basis calculations related to maximum assumed fouling factors, tube plugging limitations, and expected flowrates. The team reviewed the requirements for periodic monitoring, trending, inspection, and cleaning of the heat exchanger to determine consistency with the performance assumptions used in the calculations of heat exchanger performance.

b. Findings

No findings of significance were identified.

.2.1.1 4 Refueling Water Storage Tank (RWST)

a. Inspection Scope

The team reviewed design basis information, supporting calculations and drawings to identify and verify design assumptions regarding level and volume of water within the RWST. These design inputs were reviewed relative to the emergency core cooling system (ECCS) pumps taking suction from the RWST and included inputs into the evaluation for NPSH available and the vortexing analysis. Additionally, the volume of the RWST tank contents transferred to the containment sump was reviewed to verify adequate consistency with RHR pump NPSH evaluations when taking suction from the containment sump during the recirculation phase of a loss-of-coolant accident. The team reviewed documentation regarding instrument uncertainty in tank level instruments and performed a walkdown to assess the RWST and its associated instrumentation conditions.

b. Findings

No findings of significance were identified.

.2.2 Detailed Operator Action Reviews (4 samples)

The team assessed manual operator actions and selected a sample of four operator actions for detailed review based upon risk significance, time urgency, and factors affecting the likelihood of human error. The operator actions were selected from a probabilistic risk assessment (PRA) ranking of operator action importance based on risk reduction worth (RAW) and risk achievement worth (RRW) values. The non-PRA considerations in the selection process included the following factors:

$ Margin between the time needed to complete the actions and the time available prior to adverse reactor consequences;

$ Complexity of the actions;

$ Reliability and/or redundancy of components associated with the actions;

$ Extent of actions to be performed outside of the control room;

$ Procedural guidance to the operators; and

$ Amount of relevant operator training conducted.

.2.2.1 Operators Align the Emergency Core Cooling Systems for Cold Leg Recirculation

a. Inspection Scope

The team selected the operator actions to establish cold leg recirculation (CLR) during a small break loss-of-coolant-accident (SBLOCA). Specifically, the actions reviewed were to transfer the emergency core cooling system (ECCS) pump suctions from the refueling water storage tank (RWST) to the containment sump. These actions included:

• Identification of low RWST level

• Verification of adequate sump level

• Stopping both residual heat removal (RHR) pumps (Unit 1 only)

• Closing the RWST-RHR pump suction valves (Unit 1 only)

• Establishing cooling to RHR heat exchangers (Unit 1 only)

• Arming the semi-automatic sump swap-over (Unit 2 only)

• Verification of semi-automatic sump swap-over actions (Unit 2 only)

• Opening the containment sump suction valves

• Starting RHR pumps (Unit 1 only)

• Aligning RHR, safety injection, high-head charging, and containment spray for sump recirculation The team selected this sample because this operator action appeared to have low margin between the time required and the time available to perform the actions and there were some unit differences associated with CLR operator actions. Unit 1 operators manually align the ECCS components for CLR, whereas Unit 2 employs a semi-automatic swap-over for CLR (a combination of automatic and manual actions). In addition, in this scenario, the RHR pumps could be operated for extended periods of time on minimum flow, because the reactor coolant system (RCS) pressure would be greater than the discharge pressure of the RHR pumps. This had the potential to pressurize the isolated RHR system and increase the differential pressure across the containment sump valves.

The team reviewed PSEGs PRA and Human Reliability Analysis (HRA) studies to assess critical operator action times for PRA success. The team interviewed licensed operators, reviewed associated operating and alarm response procedures, walked down applicable panels in the main control room and in the simulator, and reviewed simulator scenarios and results. The team compared the available time, based on the identified equipment and operating limits, against operator simulator performance and expected operator response based on nominal procedure usage demonstrated during licensed operator training. The team evaluated those time margins to verify the reasonableness of PSEG's operating and risk assumptions. The team also performed main control room walkdowns to independently assess operator task complexity and emergency operating procedure (EOP) clarity.

The team interviewed licensed operators and training staff personnel, and reviewed procedures and simulator scenarios to independently evaluate the operator response time associated with stopping RHR pumps during various small break LOCA scenarios to preclude undesirable RHR system pressurization (see Section 1R21.2.1.6). In addition, the team walked down accessible portions of the ECCS systems to independently assess PSEGs configuration control and the material condition of the associated structures, systems, and components.

b. Findings

No findings of significance were identified.

.2.2.2 Operators Provide an Alternate Suction Supply for Auxiliary Feedwater

a. Inspection Scope

The team selected the manual operator actions to establish an alternate source of suction water to the auxiliary feedwater (AFW) pumps in response to a loss of the normal AFW supply. Specifically, the actions reviewed were to align the demineralized water storage tanks (DWSTs), fire water storage tank, and/or service water to supply the AFW pump suctions. The team selected this sample because of the extent of actions performed outside of the control room and the infrequent operation of this alignment.

The team reviewed PSEGs PRA and HRA studies to determine when and how quickly operators should provide alternate AFW supply for PRA success. The team interviewed equipment operators, reviewed associated operating and alarm response procedures, walked down applicable panels in the main control room and systems in the plant, reviewed test results, and observed an equipment operator simulate the in-field portions of the procedure to evaluate the ability of the operators to perform the required actions.

In addition, the team independently assessed PSEGs configuration control and the material condition of the associated tanks, valves, piping, and pre-staged equipment.

b. Findings

No findings of significance were identified.

.2.2.3 Operators Shutdown from the Remote Shutdown Panels Following Control Room

Evacuation

a. Inspection Scope

The team selected the manual operator actions to monitor and control plant shutdown from the remote shutdown panels following a control room evacuation. The team selected this sample because of the complexity of the actions, extent of actions performed outside of the control room, and the required coordination of multiple operators in different field locations.

The team interviewed equipment and licensed operators, reviewed associated operating and alarm response procedures, walked down applicable panels throughout the plant, reviewed functional test results, and observed operators simulate the in-field portions of the procedure to evaluate the ability of the operators to perform the required actions. In addition, the team independently assessed PSEGs configuration control and the material condition of the associated valves, instrumentation, panels, and pre-staged equipment.

b. Findings

No findings of significance were identified.

.2.2.4 Operators Initiate Feed and Bleed

a. Inspection Scope

The team selected the manual operator action to establish feed and bleed in response to a loss-of-secondary heat sink. Specifically, the operator action involved initiating a safety injection (SI), verifying SI valve alignment and pump running, and opening both pressurizer power operated relief valves (PORVs). The team selected this sample because of the associated RAW and the reliability and/or redundancy of components associated with the actions.

The team interviewed licensed operators, reviewed associated operating and alarm response procedures, walked down applicable panels in the main control room and injection sources in the plant, and reviewed simulator scenarios to evaluate the ability of the operators to perform the required action. The team also reviewed equipment deficiency reports, engineering evaluations, and surveillance test results to assess the performance and material condition of the associated pumps, valves, and support systems. In addition, the team reviewed and independently verified through walkdowns, PSEGs design and configuration control regarding industry operating experience related to potential low suction pressure trips of AFW pumps since this could be a contributor to the loss-of-secondary heat sink scenario.

b. Findings

No findings of significance were identified.

.2.3 Review of Industry Operating Experience and Generic Issues (4 samples)

a. Inspection Scope

The team reviewed selected operating experience issues for applicability at the Salem Nuclear Generation Station. The team performed a detailed review of the operating experience issues listed below to verify that PSEG had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.3.1 NRC GL 2006-02, Grid Reliability

The team reviewed the Salem responses to address GL 2006-02 in regard to the stations interface and coordination with the transmission system operator (TSO) for station voltage requirements, notification setpoint agreements with the TSO during impaired or potentially degraded grid conditions, and house load values supplied by Salem to the TSO to verify they were adequate and appropriately implemented.

.2.3.2 NRC Information Notice 2006-31, Inadequate Fault Interrupting Rating of Breakers

The team reviewed the applicability and actions taken by Salem to address NRC Information Notice (IN) 2006-31 which discussed concerns of inadequate fault interrupting rating of breakers. Salem electrical calculations were reviewed to verify that the postulated worst case fault currents were within the breaker, switchgear, and bus ratings.

.2.3.3 NRC Information Notice 2006-26, Failure of Magnesium Rotors in MOV Actuators

The team reviewed the applicability and actions taken by Salem to address IN 2006-26 which discussed three recent examples of MOV failures due to magnesium rotor degradation, described three failure modes, and provided references for potential corrective and preventive actions to address the degradation mechanisms. The team specifically reviewed Salems action plan to address inspections for magnesium rotor degradation for the high risk MOVs, along with reviewing actual results of boroscope inspections performed during the last refueling outage for applicable high risk valves.

.2.3.4 NRC Information Notice 97-40, Potential Nitrogen Accumulation Resulting From

Backleakage From Safety Injection Tanks The team reviewed PSEGs disposition of IN 97-40, which discussed the potential for nitrogen accumulation in interfacing systems resulting from backleakage from safety injection tanks (SI accumulators). The team reviewed PSEGs ECCS system health reports, operating logs, corrective action reports, accumulator leakage trending, ECCS system drawings, and ECCS surveillance tests to assess PSEGs vulnerability and sensitivity to potential gas voiding issues. The team discussed ECCS system venting procedures and gas voiding concerns with plant operators and design engineering. The team walked down PSEGs monthly ECCS fill and vent procedure for both units with an equipment operator to independently assess system high points and procedure clarity.

Additionally, the team independently walked down accessible portions of the ECCS systems to assess the material condition of the associated valves, piping, and piping supports.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (IP 71152)

The team reviewed a sample of problems that PSEG had previously identified and entered into their corrective action program. The team focused the review of these issues on selected components identified for inspection. The review was performed to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, notifications written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the corrective action system. The specific corrective action documents that were sampled and reviewed by the team are listed in the attachment.

b. Findings

No findings of significance were identified.

4OA6 Meetings, including Exit

The team presented the inspection results to Mr. Robert Braun, and other members of PSEGs staff at an exit meeting on August 8, 2008. On September 22, 2008, a telephone call was held with Mr. R. Villar to discuss a change in the aspect of the crosscutting issue associated with one of the findings as discussed during the exit meeting. The inspectors verified that there is no proprietary information in this report.

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Braun Site Vice President

M. Gwirtz Director Operations

E. Eilola Acting Site Engineering Director

A. Johnson Mechanical/Structural Design Manager

J. Hilditch Senior Engineer

L. Rajkowski Senior Design Engineering Manager

E. Villar Licensing Engineer

LIST OF ITEMS

Opened and Closed

NCV

05000272-311/2008007-01 Inadequate Design Control for MOV Capability Assessments (Section 1R21.2.1.3)

NCV

05000272-311/2008007-02 Inadequate Design Control for MOV Thermal Overload Protection Devices NCV

05000311/2008007-03 Inadequate Design Control for Unit 2 Containment Sump Valve Design DP Determination

Opened

URI

05000272-311/2008007-04 Vital Bus Degraded Voltage Licensing Bases