IR 05000354/2006002

IR 05000354-06-002 on 01/01/2006 - 03/31/2006 for Hope Creek Generating Station; Heat Sink Performance, Maintenance Effectiveness, Other Activities

ML061320570
Person / Time
Site:	Hope Creek
Issue date:	05/11/2006
From:	Mel Gray Reactor Projects Branch 3
To:	Levis W Public Service Enterprise Group
Gray M, RI/DRP/Br3 610-337-5209
References
IR-06-002
Download: ML061320570 (50)

Text

SUBJECT:

HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000354/2006002

Dear Mr. Levis:

On March 31, 2006, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Hope Creek Nuclear Generating Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 3, 2006, with Mr. George Barnes and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents two NRC-identified findings and one self-revealing finding of very low safety significance (Green). These three findings were determined to involve violations of NRC requirements. Additionally, three licensee-identified violations which were determined to be of very low safety significance are listed in the report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) 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 Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Hope Creek Generating Station.

Mr. 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 NRC's 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/

Mel Gray, Chief Projects Branch 3 Division of Reactor Projects Docket No: 50-354 License No: NPF-57 Enclosure: Inspection Report 05000354/2006002 w/Attachment: Supplemental Information cc w/encl:

G. Barnes, Site Vice President D. Winchester, Vice President - Nuclear Assessments W. F. Sperry, Director - Business Support D. Benyak, Director - Regulatory Assurance M. Massaro, Hope Creek Plant Manager J. J. Keenan, Esquire M. Wetterhahn, Esquire Consumer Advocate, Office of Consumer Advocate F. Pompper, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director of Radiation Protection and Release Prevention, State of New Jersey K. Tosch, Chief, Bureau of Nuclear Engineering, NJ Dept. of Environmental Protection H. Otto, Ph.D., DNREC Division of Water Resources, State of Delaware N. Cohen, Coordinator - Unplug Salem Campaign W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance

M

SUMMARY OF FINDINGS

IR 05000354/2006002; 01/01/2006 - 03/31/2006; Hope Creek Generating Station; Heat Sink

Performance, Maintenance Effectiveness, Other Activities.

The report covered a 13-week period of inspection by resident inspectors and announced inspections by regional reactor inspectors. Three Green non-cited violations (NCVs) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using 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 3, dated July 2000.

Cornerstone: Mitigating Systems

C

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for PSEGs failure to implement corrective actions for a condition adverse to quality involving inadequate procedure guidance for service water pump packing replacement. This resulted in a degraded condition on the 'B' service water pump packing assembly that was identified by the inspectors on February 13, 2006. PSEG's corrective actions included tightening the packing and revising maintenance procedures.

The finding was more than minor because it was associated with the equipment performance 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. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 SDP screening and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, and did not screen as risk significant due to external events. The finding had a cross-cutting aspect in the area of problem identification and resolution because PSEG did not identify that corrective actions were not implemented correctly during a corrective action effectiveness review. (Section 1R07)

C

Green.

The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion XVI, "Corrective Action," when the D service water strainer was rendered unavailable for 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br /> on November 6, 2005. On May 23, 2005,

PSEG technicians reassembled the D service water strainer with the backwash arm off-center and a packing gland machined from its original size to allow assembly. The resulting non-conforming condition was not entered into PSEGs iii corrective action program. The absence of this documentation and evaluation led to the reuse of the machined gland, which resulted in a packing leak and the unavailability of the 'D' service water strainer in November 2005. PSEG initiated actions to address the problem associated with not entering the non-conforming condition into the corrective action program.

This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems and Initiating Events cornerstone objectives and affected both cornerstone objectives. In accordance with NRC Inspection Manual Chapter 0609, Appendix A,

"Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 SDP screening and determined a more detailed Phase 2 evaluation was required to assess the safety significance, because the finding affected two cornerstones. The inspectors determined that the finding was of very low safety significance (Green). The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because PSEG did not identify a condition adverse to quality by entering the issue into the corrective action program. (Section 1R12)

C

Green.

A self-revealing, non-cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action," was identified when the guide vane pivot arm on the 'A'

control room chiller was discovered to be operating incorrectly in May 2005, rendering the chiller unable to perform its design function. PSEG corrective actions included modifying applicable procedures and providing training to maintenance technicians.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. The improper use of setscrews on the

'A' control room chiller guide vane arms resulted in the chiller not being able to perform its design function and unplanned unavailability of the chiller for about 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br /> to implement repairs. The inspectors completed a Phase 1 screening using Appendix A of Inspection Manual Chapter (IMC) 0609, Determining the Significance of Reactor Inspection Findings for At-Power Situations, and determined that the performance deficiency was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train greater than its technical specification allowed outage time, and did not screen as risk significant due to external events.

(Section 4OA3)

Licensee Identified Violations

Violations of very low safety significance, which were identified by PSEG have been reviewed by the inspectors. Corrective actions taken or planned by PSEG have been entered into PSEG's corrective action program. These violations and corrective actions are listed in Section 4OA7 of this report.

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REPORT DETAILS

Summary of Plant Status

Hope Creek began the quarter operating at 100 percent (%) power. On January 14, 2006, an electrical transient in non-vital 13kV bus-work caused a loss of the in-service offgas recombiner train. Hope Creek reduced power to approximately 80% in accordance with plant procedures because main condenser vacuum was degrading due to the loss of the offgas recombiner train.

Operators reduced power to 71% in accordance with procedures to clear increased vibration readings on the A and B reactor recirculation pumps. Power was further reduced to 60% to perform scheduled control rod scram time testing. The plant was returned to 100% power on January 15, 2006.

On February 4, 2006, control room operators de-energized the 10B110 125V bus due to a report of smoke from a breaker powered from the bus. This caused a recirculation pump runback because the A primary condensate pump tripped when 10B110 was deenergized.

Plant power was stabilized at 54% following the runback. The plant was returned to 100%

power on February 5, 2006, and remained at 100% power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a.

Inspection Scope (1 sample)

The inspectors reviewed adverse weather preparation activities related to the potential for river grass intrusion conditions. Inspectors assessed implementation of PSEGs grassing readiness plan through plant walkdowns, corrective action program review, and discussions with cognizant managers and engineers. Documents reviewed by inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial Walkdown (4 samples)

a. Inspection Scope

The inspectors performed a partial walkdown of the following four systems to verify the operability of redundant or diverse trains and components when safety equipment was inoperable. The inspectors attempted to identify any discrepancies that could impact the function of the system, and therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, walked down control systems components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program. Documents reviewed are listed in the attachment.

C A emergency diesel generator (EDG) and 10A401 switchgear equipment during maintenance on the B EDG on January 30, 2006; C B residual heat removal (RHR) pump and heat exchanger during maintenance on the A RHR pump on March 1, 2006; C A & C core spray loops during maintenance on B & D core spray trains on February 15, 2006; and C Safety auxiliaries cooling system throttled valves on February 28, 2006.

.2 Complete Walkdown (1 sample)

a. Inspection Scope

The inspectors conducted one complete walkdown of accessible portions of the standby liquid control (SLC) system on February 9 and 10, 2006. The inspectors used PSEG procedures and other documents listed below to verify proper system alignment and functional capability:

C Procedure HC.OP-SO.BH-0001, Standby Liquid Control System Operation; C HC.OP-IS.BH-0001, Standby Liquid Control Pump - AP208 - Inservice Test; C HC.OP-IS.BH-0002, Standby Liquid Control Pump - BP208 - Inservice Test; C HC.OP-IS.BH-0101, Standby Liquid Control System Valves - Inservice Test; C HC.OP-ST.BH-0001, SLC Valve Operability Test - Monthly; C HC.CH-SA.BH-0001, Sampling The Standby Liquid Control System; and C Drawing No. M-48-1, Standby Liquid Control.

The inspectors also verified SLC electrical power requirements, labeling, operator workarounds, hangers and support installation, and associated support systems status.

The walkdowns also included evaluation of system piping and equipment against the following considerations:

C Oil reservoir levels appeared normal; C Snubbers did not appear to be leaking hydraulic fluid; C Hangers were functional; C Long-term scaffold construction and placement; and C Valves aligned correctly to support injection.

In addition, the inspectors reviewed outstanding maintenance work orders to verify that the deficiencies did not significantly affect the SLC system function and were being identified and appropriately resolved.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

(10 samples)

The inspectors conducted a tour of the ten areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEGs administrative procedures; fire detection and suppression equipment was available for use; passive fire barriers were maintained in good material condition; and compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEGs fire plan. Documents reviewed are listed in the attachment.

C A, B, C, and D fuel oil storage tank (FOST) rooms on January 3-4, 2006; C A residual heat removal heat (RHR) exchanger and pump rooms on January 5, 2006; C B RHR exchanger and pump rooms on January 5, 2006; C A, B, C, and D core spray pump rooms on January 18, 2006; C High pressure coolant injection pump and turbine room on January 18, 2006; C Reactor core isolation cooling pump and turbine room on January 18, 2006; C Lower Control Equipment Room on January 31, 2006; C Electrical access area elevation on January 31, 2006; C Class 1E switchgear rooms on January 31, 2006; and C Control equipment, HVAC, Inverter & battery rooms on January 31, 2006.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

(1 sample)

The inspectors reviewed selected risk-important plant design features and PSEG procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors focused on mitigation strategies and equipment in the emergency diesel generator fuel oil storage tank (FOST) rooms. The inspectors reviewed flood analysis and design documents, including the updated final safety analysis report (UFSAR), engineering calculations, and abnormal operating procedures.

The inspectors observed the condition of wall penetrations, flood alarm switches, and drains to assess their readiness to contain flow from an internal flood in accordance with the design basis. In addition, the inspectors reviewed PSEG drawings and performed walkdowns of the FOST rooms on January 3-5, 2006, to assess potential flooding vulnerabilities.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

(3 samples)

Based on a plant specific risk assessment and previous inspections, the inspectors selected three heat exchanger (HX) samples for this review: the A1 safety auxiliaries cooling system (SACS) HX, the A residual heat removal (RHR) HX, and the B RHR HX. SACS provides cooling to the RHR HXs and transfers its heat load to the service water (SW) system via the SACS HXs. The SW system supplies cooling water from the Delaware River (the ultimate heat sink).

The inspectors reviewed PSEGs methods (inspection, cleaning, maintenance, and performance monitoring) used to ensure heat removal capabilities for the SACS HXs and compared them to PSEGs commitments made in response to Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The inspectors verified that periodic SW side pressure drop readings for the SACS HXs had been recorded in order to monitor for potential macro-fouling conditions. The inspectors reviewed the eddy current test methodology and results to verify that the number of plugged SACS HX tubes was bounded by assumptions in the engineering analyses.

The inspectors reviewed the design fouling factor assumptions for the RHR HXs and the engineering analyses of minimum calculated SACS flowrate to the RHR HXs. This review was performed to verify that the minimum calculated SACS flowrate, in conjunction with the heat transfer capability of the RHR HXs, supported the minimum heat transfer rates assumed during accident and transient conditions. The inspectors reviewed RHR HX modeling analyses against the HX specification sheets to ensure the analysis was valid. This included calculations related to minimum allowable SACS flowrate to the HXs. The inspectors also reviewed SW silt survey results and engineerings associated trending data and action plans.

The inspectors compared surveillance test and inspection data to the established acceptance criteria to verify that the results were acceptable and that operation was consistent with design. The inspectors walked down the selected HXs, control room instrumentation panels, the chlorination system, and the SW system to assess the material condition of these systems and components.

The inspectors also reviewed a sample of corrective action notifications related to the selected HXs, SACS, and the SW system to ensure that PSEG appropriately identified, characterized, and corrected problems related to these essential systems and components. Documents reviewed are listed in the attachment.

.1 Service Water Pump Packing Gland Follower Degraded

Introduction:

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because corrective actions were not implemented for a condition adverse to quality involving inadequate procedure guidance for a SW pump packing replacement.

Description:

On July 14, 2004, a PSEG equipment operator observed excessive packing leakage on the B SW pump. PSEG personnel determined that the nuts on the pump packing gland had backed off and disengaged on three of the four studs. The nut remained threaded on the fourth stud; however, the stud had backed out of the pump casing. As a result, the gland rotated approximately two inches from its bolted position and caused excessive packing leakage. Operations personnel removed the B SW pump from service and declared the pump inoperable due to the high packing leakage.

PSEGs apparent cause evaluation (70040441) determined that guidance contained in maintenance procedure HC.MD-CM.EA-0001(Q), Rev. 20, Service Water Pump &

Motor Removal & Replacement, was inadequate because the procedure did not include vendor manual (VTD 322416) direction to verify the required packing height and ensure the gland follower could be inserted between 1/8 and 3/16 inches into the stuffing box.

(See NRC Inspection Report 50-354/2004004, Section 1R12).

On February 13, 2006, the inspectors observed during a plant walkdown that all four B SW pump packing gland follower nuts were loose, lacked adequate thread engagement, and had backed off the gland follower (from 0.25" to 1.5" approximately). The B SW pump was in standby at the time of discovery. Operators promptly hand-tightened the nuts, placed the B SW pump in service, directed maintenance to adjust the packing nuts using procedure HC.MD-CM.EA-0001, and initiated corrective action notification

===20271832. Following the packing adjustment, operators noted that the pump leak-off and packing gland temperature were within the expected range and that there was no apparent degradation in pump performance. Operators declared the pump operable and initiated a compensatory measure for increased monitoring by equipment operators.

PSEGs corrective action to address the July 2004 pump packing failure was to revise maintenance procedure HC.MD-CM.EA-0001. This was originally scheduled to be completed by September 24, 2004. The inspectors noted that PSEG extended this due date several times resulting in the issuance of HC.MD-CM.EA-0001, Revision 21 on February 24, 2005. The inspectors identified that PSEG replaced and re-packed the B SW pump on October 1, 2004, using HC.MD-CM.EA-0001 (Revision 20), which did not include the additional guidance for packing and gland follower placement (60038786 operation 586). The inspectors also identified that PSEG missed an opportunity to identify this problem on May 26, 2005, when they completed a corrective action effectiveness review of the July 2004, SW bolting issue (70040441 operation 090).

PSEG documented in notification 20271832 that the identified adverse condition could unbolt the packing gland follower allowing SW pressure to drive the packing out of the stuffing box. This would result in high packing leakage and potentially starve lube water flow from the pumps lower bearing. Engineering noted that the B SW pump was last in service on February 12, 2006, when it ran for ten hours without observed excessive packing leakage. Engineering later determined the degraded packing gland follower bolting condition did not adversely affect the pumps ability to perform its design function (70054180 operation 030). Engineering determined that the B SW pump had remained operable from October 1, 2004, through February 13, 2006.

Analysis:

A performance deficiency was identified in that PSEG did not implement corrective actions to prevent a recurring condition adverse to quality on the B SW pump that was identified on February 13, 2006. The finding was more than minor because it was associated with the equipment performance 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. The inspectors determined the reliability of the 'B' SW pump was affected because the inspectors observed the packing gland studs were similarly backing off in July 2004, and the pump packing subsequently failed within a number of days. (Reference NRC Inspection Report 50-354/2004004, Section 1R12) In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 SDP screening and determined the finding to be of very low safety significance (Green). The finding had a cross-cutting aspect in the area of problem identification and resolution because PSEG did not identify that corrective actions were not implemented prior to maintenance on the B SW pump on October 1, 2004, during a corrective action effectiveness review performed in May 2005.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, on October 1, 2004, PSEG failed to implement corrective actions to ensure that the packing gland follower was properly installed on the B SW pump. The condition adverse to quality was observed on February 13, 2006. However, because the finding was of very low safety significance and has been entered into the corrective action program in notifications 20271832 and 20279721, this violation is being treated as a NCV, consistent with section VI.A.1 of the NRC Enforcement Policy: NCV 05000354/2006002-01, Failure to Implement Corrective Actions for Service Water Pump Packing.

.2 Residual Heat Removal Heat Exchanger Flow Testing Issue

The NRC safety evaluation for Technical Specification (TS) Amendment No. 94, associated with TS 4.6.2.3.b, stated, The NRC staff concludes that the currently demonstrated flow through the residual heat removal (RHR) heat exchangers is adequate and that bypass flow is not excessive considering the selection of a butterfly valve for flow control. In addition, the proposed periodic testing of RHR heat exchanger (HX) flow, and butterfly valve leakage, will detect component degradation in a timely manner. The purpose of this periodic test (once per operating cycle) is to ensure that the design basis flow is maintained to the RHR HXs in the suppression pool cooling (SPC) mode and that the HX bypass flow is limited. The inspectors noted that PSEG appropriately documented this requirement in the TS 4.6.2.3.b bases. The TS 4.6.2.3.b bases state, in part, by establishing a maximum 250 gpm leakage rate for the heat exchanger bypass valves and opening the test return valve fully, a constant system resistance is established for every pump test required by Surveillance Requirement 4.6.2.3.b. RHR pump degradation would then be more readily detectable if the total flow decreased between tests.

PSEG performed RHR HX flow testing using procedure HC.OP-ST.BC-0009, Residual Heat Removal System RHR Heat Exchanger Flow Measurement - 18 Month. After reviewing the last surveillance test (ST) performed for each RHR HX, the inspectors observed that:

(1) the 18-month ST did not provide direction on how to calculate RHR HX and bypass flows;

(2) the 18-month ST did not provide direction on placement of ultrasonic flow instruments, calibration of these instruments, or required accuracy and range of these instruments;

(3) PSEG used temporarily installed measuring and test equipment (M&TE) having a minimum accuracy of +/- 0.5% for the RHR combined (HX &

bypass) flow rate during the quarterly RHR pump ST, but used less accurate installed plant instrumentation for the 18 month ST;

(4) PSEG did not use the recorded ultrasonic flow instrument data on the RHR HX outlet lines in their calculation of HX flow (this temporary instrument was specifically installed for this flow test); and

(5) the 35 sets of recorded data for each HX appeared erratic [for A RHR HX: the HX flow was 10,439 gpm with a standard deviation (STD) of 131 gpm (required flow $ 10,280 gpm); bypass flow was 200 gpm with a STD of 122 gpm (required flow # 250 gpm); for B RHR HX:

the HX flow was 10,349 gpm with a STD of 138 gpm; bypass flow was 239 gpm with a STD 138 gpm]. PSEG initiated notification 20272419 to evaluate these issues. In addition, the inspectors identified that engineering apparently non-conservatively calculated the B RHR HX flow during the last 18 month ST (averaging the combined flow vice subtracting out the bypass flow). This resulted in engineering documenting a flow of 10,588 gpm vice an actual flow of 10,349 gpm. PSEG initiated notification 20273368 to evaluate this issue.

The inspectors determined that the RHR HX flow testing issue will be treated as an unresolved item (URI), pending completion of a technical evaluation by PSEG. An unresolved item is an issue requiring further information to determine if it is acceptable, if it is a finding, or if it constitutes a deviation or violation of NRC requirements. In this case, additional NRC review will be required to further assess PSEGs evaluation of their methodology, including instrument accuracy and uncertainty, used to calculate the RHR HX and bypass flows once per cycle. Specifically, the NRC will assess whether the testing demonstrates that the RHR HX flow is adequate, that the HX bypass flow is within specification (does not exceed 250 gpm), and that the validity of TS 4.6.2.3.b required testing is maintained. (URI 05000354/2006002-02, RHR HX Flow Testing Methodology)

=

Resident Inspector Quarterly Review On February 21, 2006, the inspectors observed a simulator training scenario to assess operator performance and training effectiveness. The scenario involved a marsh grass intrusion that impacted station service water, a primary condensate pump trip that caused a full recirculation system runback, a main condenser vacuum leak leading to a reactor scram, and main steam isolation valve closure. The inspectors assessed simulator fidelity and observed the simulator instructors critique of operator performance.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Maintenance Effectiveness Inspection

a. Inspection Scope

(3 samples)

The inspectors reviewed performance monitoring and maintenance activities for the three systems or component issues identified below to determine whether PSEG was adequately monitoring equipment performance to ensure maintenance activities were effective in maintaining the equipment reliable. Specifically, the inspectors reviewed the samples listed below for items such as:

(1) appropriate work practices;

(2) identifying and addressing common cause failures;

(3) scoping in accordance with 10 CFR 50.65(b) of the maintenance rule (MR);

(4) characterizing reliability issues for performance;

(5) trending key parameters for condition monitoring;

(6) charging unavailability for performance;

(7) classification and reclassification in accordance with 10 CFR 50.65 (a)(1) or (a)(2); and

(8) appropriateness of performance criteria for structures, systems, and components classified as (a)(2). Documents reviewed are listed in the attachment.

C A residual heat removal (RHR) pump breaker failure on March 1, 2006; C B technical support center chilled water system spurious start and trip on March 3, 2006; and C D service water strainer packing failure on November 6, 2005.

b. Findings

Introduction:

The inspectors identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," when the D service water strainer packing failed, causing excessive leakage and resulting in the D service water strainer being removed from service for emergent work repair.

Description:

PSEG replaced the D service water strainer under work order 60039109 during a planned service water outage from May 9-23, 2005. Maintenance technicians could not center the backwash arm shaft in the strainer lid stuffing box during strainer reassembly per procedure HC.MD-CM.EA-0003(Q), Service Water Strainer Overhaul and Repair, because the backwash arm was mechanically interfering with the packing gland follower. PSEG engineering instructed the maintenance personnel to increase the diameter of the gland follower by machining to remove the mechanical interference as an alternative to centering the shaft by adjusting the position of the gear reducer housing. Centering the gear reducer housing would have required machining new alignment holes in the reducer base plate because of an alignment mismatch between a base plate and strainer lid that was not discovered until reassembly. PSEG machined the gland follower, assembled the strainer, and returned the strainer to service on May 22, 2005.

Contrary to PSEGs procedure NC.WM-AP.ZZ-0000, Notification Process, PSEG did not generate a notification to identify that the D service water strainer was reassembled with a machined gland follower and the backwash arm was not centered per the overhaul procedure.

On October 3, 2005, a packing leak on the D service water strainer was documented in notification 20254749. PSEG replaced the packing during a planned maintenance window from October 30 to November 3, 2005, under work order 60039109.

On November 4, 2005, equipment operators observed that D service water strainer had excessive packing leakage with a portion of the packing extruding from underneath the previously machined gland follower. PSEG declared the D service water pump inoperable on November 4, 2005, at 12:56 pm. Emergent maintenance was performed under work order 60058794 to repair the strainer. Maintenance personnel centered the backwash arm shaft in the stuffing box by centering the gear reducer above the stuffing box. Also, the packing and packing gland follower were replaced. The strainer was declared operable on November 6, 2005, at 2:02 pm.

The inspectors noted that PSEG wrote a notification to repair the strainer, but did not evaluate the cause of the equipment failure. Following discussions between the inspectors and PSEG engineers, PSEG evaluated the equipment failure under order

===70052345. PSEG concluded there was inadequate implementation of the corrective action process to properly identify and correct this issue. PSEG also determined that procedure HC.MD-CM.EA-0003(Q), Service Water Strainer Overhaul & Repair, was inadequately detailed to ensure the backwash arm shaft is centered. PSEG engineers recommended an enhancement to revise the procedure to include direction to position the backwash arm shaft in the stuffing box, including nominal dimensions and acceptance criteria.

Analysis:

The inspectors determined that the failure to identify an as-left non-conforming condition on the 'D' SW strainer in May 2005, that consisted of the machined gland follower and un-centered backwash arm, was a performance deficiency and a finding. Specifically, PSEG did not identify a non-conforming condition by entering it in the corrective action program, which was contrary to PSEG procedure NC.WM-AP.ZZ-0000, Notification Process. The absence of this documentation and evaluation led to the reuse of the machined gland follower in October 2005, during reassembly of the strainer. This resulted in a packing leak on November 4, 2005, and approximately 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br /> of D service water strainer unavailability. This finding had cross-cutting aspects in problem identification and resolution because PSEG did not properly identify a condition adverse to quality, in that the non-conforming conditions were not entered into the corrective action program.

This issue was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This issue also impacted the initiating events cornerstone because unavailability of one service water pump increased the likelihood of loss of service water events. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 SDP screening and determined a more detailed Phase 2 evaluation was required to assess the safety significance because the finding affected two cornerstones. The inspectors determined that the finding was of very low safety significance (Green). The inspectors utilized an exposure period of less than three days due to the strainer being unavailable for 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br />. The performance deficiency directly affected the probability of a loss of service water; therefore, the likelihood of a loss of service water event was increased by one order of magnitude. All of the mitigating systems equipment listed on the Phase 2 worksheet for a loss of service water event were unaffected by the finding and operator recovery actions were credited. The most predominant core damage sequence was an inadvertent/stuck-open relief valve with a failure of high pressure coolant injection and a failure of the operators to depressurize.

Enforcement:

10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG failed to identify that a gland follower was machined to allow the D service water strainer to be assembled with the backwash arm not centered. This performance deficiency led to excessive packing leakage of the D service water strainer on November 4, 2005, and the unavailability of the D service water train for 49 hours5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br />. Because this finding is of very low safety significance and has been entered into PSEGs corrective action program (notifications 20264237 and 20279713) this finding is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000354/2006002-03, Failure to Identify Conditions Adverse to Quality on the D Service Water Strainer.

=

The inspectors conducted a review of the periodic evaluation of implementation of the maintenance rule as required by 10 CFR 50.65(a)(3) for Hope Creek. The evaluation covered a period from July 2003 to May 2005. The purpose of this review was to ensure that Hope Creek established appropriate goals and effectively assessed system performance and preventive maintenance activities. The inspectors verified that the evaluation was completed within the required time period and that industry operating experience was utilized, where applicable. Additionally, the inspectors verified that Hope Creek appropriately balanced equipment reliability and availability and made adjustments when appropriate.

The inspectors selected a sample of five risk-significant systems to verify that

(1) the structures, systems, and components were properly characterized;

(2) goals and performance criteria were appropriate;

(3) corrective action plans were adequate; and

(4) performance was being effectively monitored in accordance with station procedures.

The following systems were selected for this detailed review:

C Fire Water System; C High Pressure Coolant Injection (HPCI);

C Radiation Instrumentation; C Safety Relief Valves (SRVs); and C Service Water System.

These systems were either in (a)(1) status, had been in (a)(1) status at some time during the assessment period, or experienced degraded performance. The inspectors reviewed corrective action documents for malfunctions and failures of these systems to determine if system failures had been correctly categorized as functional failures and system performance was adequately monitored to determine if classifying a system as (a)(1) was appropriate.

The inspectors interviewed the maintenance rule coordinator, engineering supervisors, and system engineers. Documentation for applicable systems and a sample of condition reports were also reviewed by the inspector. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(5 samples)

The inspectors reviewed five on-line risk management evaluations through direct observation and document reviews for the following configurations:

C B diesel area panel room supply ventilation fan inoperability during C emergency diesel generator planned maintenance on January 11, 2006; C A station auxiliaries cooling system (SACS) pump inoperability during B channel maintenance and testing week on January 19, 2006; C High grassing condition during D service water strainer planned maintenance on February 13, 2006; C B technical support center chilled water system unavailability from March 3 through March 8, 2006; and C Trip of A and B control room chillers on March 14, 2006.

The inspectors reviewed the applicable risk evaluations, work schedules and control room logs for these configurations to verify that concurrent planned and emergent maintenance and test activities did not adversely affect the plant risk already incurred with these configurations. PSEGs risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEGs on-line risk monitor (Equipment Out Of Service workstation) to gain insights into the risk associated with these plant configurations. Finally, the inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R14 Operator Performance During Non-Routine Evolutions and Events

a. Inspection Scope

(2 samples)

The inspectors evaluated PSEGs performance and response during non-routine evolutions to determine whether the operator responses were consistent with applicable procedures, training, and PSEGs expectations. The inspectors observed control room activities and reviewed control room logs and applicable operating procedures to assess operator performance. PSEGs evaluations of operator performance were also reviewed. The inspectors walked down control room displays and portions of plant systems to verify status of risk significant equipment and interviewed operators and engineers. Documents reviewed are listed in the attachment.

Reactor Recirculation Pump Vibration Monitoring. The inspectors periodically monitored reactor recirculation pump performance and verified that reactor recirculation pump vibration monitoring equipment was maintained to implement commitments to NRC Confirmatory Action Letter (CAL) 1-05-001. The inspectors also reviewed operations and engineering department personnel response to vibration alarms on the A and B reactor recirculation pumps between January 1 and March 31, 2006, that occurred when operators changed pump speed in accordance with plant procedures. The alarm conditions were documented in corrective action notifications 20267957 and 20270414.

The inspectors verified that operators properly responded to these alarms in accordance with alarm response procedure HC.OP-AR.ZZ-0008(Q), Rev. 30, Overhead Annunciator Window Box C1, and abnormal procedure HC.OP-AB.RPV-0003(Q),

Rev. 10, Recirculation System/Power Oscillations. The inspectors also verified implementation of engineering procedure HC.ER-AP.BB-0001(Q), Revs. 4 and 5, Reactor Recirculation Pump/Motors Vibration Monitoring. The inspectors, with assistance from personnel in the Office of Nuclear Reactor Regulation (NRR), Division of Engineering, reviewed PSEGs evaluation of the alarm conditions which concluded, in each case, the condition experienced was not representative of shaft cracking.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

b. Inspection Scope

(6 samples)

The inspectors reviewed six issues involving potentially degraded plant equipment associated with:

C A service water pump IST adverse trend reported on January 20, 2006; C B technical support center (TSC) chilled water system spurious start and trip on March 3, 2006; C D service water strainer gear box shear pin failure and scored backwash arm shaft on February 12, 2006; C Operability Determination 70053797 associated with safety auxiliaries cooling valves found throttled incorrectly during engineering review on February 13, 2006; C Drywell cooler condensate flow meter operability on February 22, 2006; and C Control room and TSC chilled water pumps requiring frequent oil additions on March 2, 2006.

The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were justified. The inspectors interviewed engineers and operators and discussed issues with PSEG management when potential issues existed with no formal operability evaluation. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEGs operability determinations.

Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. Notifications and documents reviewed in this regard are listed in the attachment.

c. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

(1 sample)

The inspectors reviewed the following design change:

C Order 80057204, equivalent change package for replacing butterfly valves in the safety auxiliary cooling system with a different style valve.

The design bases, licensing bases, modification instructions and post-modification testing of the affected components were reviewed to verify the performance capability of this equipment was not adversely affected. The inspectors reviewed the applicable technical specifications for this equipment to ensure that operability requirements and allowable outage time limits were met. The inspectors also reviewed notifications documenting deficiencies identified related to permanent plant modifications. The documents reviewed as part of these inspections are listed in the attachment.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

(6 samples)

The inspectors reviewed the six post-maintenance tests listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed test procedures to verify the procedure adequately tested the safety functions that may have been affected by the maintenance activity and the acceptance criteria in the procedure were consistent with the UFSAR and other design basis documentation. The inspectors also witnessed the test or reviewed the test data to verify test results adequately demonstrated restoration of the affected safety functions.

Documents reviewed are listed in the attachment.

C WOs 30047121, 50077555, 50077541, high pressure coolant injection (HPCI)motor-operated valves 1BJHV-F004, 1BJHV-F059, and 1APHV-F011 on January 3, 2006; C WO 30110360, C emergency diesel generator on January 14, 2006; C WO 30133318, B intermediate range neutron monitor on January 19, 2006; C WO 60038972, B control room emergency filtration train on January 26, 2006; C WO 50091404, A station auxiliaries cooling water pump on February 2, 2006; and C WO 60060628, B primary containment instrument gas compressor on February 16, 2006.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

(5 samples)

The inspectors witnessed surveillance tests or reviewed test data of five risk-significant structures, systems, and components (SSCs) listed below to assess whether the SSCs met the requirements of the technical specifications, UFSAR, and other plant design documents. The inspectors also determined whether the testing effectively demonstrated that the SSCs were operationally ready and capable of performing their intended safety functions. Documents reviewed are listed in the attachment.

C Reactor coolant system leakage detection daily surveillance data (drywell floor sump and air cooler condensate flow rates) on January 20, 2006; C A residual heat removal pump inservice test on February 2, 2006; C B & D core spray pumps inservice test on February 16, 2006; C High pressure coolant injection main and booster pump set inservice test on February 28, 2006; and C Redundant reactivity control system division 1 channel A ATWS recirculation pump trip functional test on March 28, 2006.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's corrective action program. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings.

.2 Annual Sample: Review of Repetitive Control Room and TSC Chiller Problems

a. Inspection Scope

The inspectors reviewed PSEGs actions to resolve problems with guide vane actuator linkage joints on refrigerant compressor units servicing chilled water systems. The guide vane actuator joints consist of two joints in the linkage, made up of a shaft and an arm that slides on the shaft and is held in place with three setscrews. Two control room chillers, 1AK400 and 1BK400, and two TSC chillers, 1AK403 and 1BK403, utilize this linkage. The inspectors reviewed LERs, notifications, evaluations, system health reports, vendor documents, and the UFSAR to understand the design, function, and failure history of the chillers. Engineers, maintenance supervisors, and other PSEG staff were interviewed to understand design and maintenance issues with the chillers.

Problem resolution efforts were discussed with plant management.

The following equipment issues were documented associated with control room chiller guide vane linkage problems:

On May 20, 2004, the B control room chiller was declared inoperable due to evaporator pressure exceeding a high set point. The resulting evaluation determined that the setscrews holding a pivot arm to the guide vane shaft were not adequately engaged to prevent the setscrews from slipping on the shaft. This failure was the subject of LER 05000354/2004-005-00 that appears in NRC Inspection Report 05000354/2004004.

On May 12, 2005, the A control room chiller was declared inoperable when plant personnel discovered arm-to-shaft slippage on another joint in the linkage associated with the guide vane actuator shaft. The slippage resulted in the chiller failing to maintain chilled water temperature at its design value. PSEG determined the slippage occurred due to loose setscrews in the guide vane actuator shaft-to-arm joint. PSEGs evaluation determined that internal and external operating experience was not used effectively to improve station maintenance procedures and training using improved practices for setting fastener parts and devices. This failure was the subject of LER 05000354/2005-004-00 that appears in section 4OA3 of this report.

On December 8, 2005, the B control room chiller was declared inoperable when equipment operators found the guide vane actuator arm slipping with respect to the shaft. PSEG secured the chiller to implement repairs that resulted in 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> of unavailability. PSEG had implemented a temporary log reading that required operators to check the status of arm to shaft slippage once per day. It was during this log reading that the slippage was identified. PSEG determined the slippage was due to inadequate setscrew engagement into the actuator shaft. PSEG also determined that inadequate instructions existed for technicians to machine dimples into the shaft to increase setscrew holding power. A licensee-identified violation associated with this issue is described in section 4OA7 of this report.

b. Observations and Findings

No findings of significance were identified.

The inspectors observed that apparent cause evaluations performed for these conditions did not consistently include some aspects of procedure NC.CA-TM.ZZ-0005(Z), Apparent Cause Evaluation Guideline. Specifically, the extent of condition and cause determinations, operating experience reviews, and maintenance practice reviews did not fully evaluate the as-found and as-left chiller linkage and fastener conditions and maintenance assembly practices.

The inspectors also noted incomplete documentation of vendor communications in accordance with procedure NC.CC-AP.ZZ-0043(Q), "Vendor Information Program." In some instances, conversations between the vendor and PSEG staff with respect to the chiller linkage problems were not documented. However, vendor information was used appropriately by PSEG to correct the specific problems.

.3 Annual Sample: Review of Extended Containment Boundary Change Problems

a. Inspection Scope

The inspectors selected notification 20265946 for detailed review. The notification was written to address the effect on the primary containment boundary when manual valve 1-AP-V044 was opened to support plant evolutions. Valve 1-AP-V044 isolates the residual heat removal (RHR) system from the condensate storage and transfer (CST)system. PSEG updated the UFSAR to move an extended containment boundary from manual isolation valve 1-AP-V044 to a set of two check valves, 1-AP-V042 and 1-AP-V043, which were downstream of the manual isolation valve. This change allowed PSEG to leave manual valve 1-AP-V044 open and use the condensate transfer system as an alternate keep-fill system when the normally-used system jockey pump is unavailable.

The inspectors reviewed notifications, interviewed plant personnel and reviewed associated documents to ensure the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were developed and implemented. Documents reviewed are listed in the attachment.

b. Findings and Observations

No findings of significance were identified.

The inspectors observed that because PSEG referenced check valves, 1-AP-V042 and 1-AP-V043, as part of a keep-fill system in the UFSAR, only one check valve was tested in accordance with the IST program. Inspectors determined that both check valves should have been tested because the two check valves, as a pair, form the extended containment boundary. Inspectors concluded that the issue was minor because one check valve was tested satisfactorily under the IST program, the check valves are of a simple design, and maintenance records indicated no significant issues with either check valve. PSEG entered the deficiency into their corrective action program under order 70053532.

.4 Safety Conscious Work Environment Metric Review

a. Inspection Scope

The inspectors reviewed PSEGs progress in addressing safety conscious work environment (SCWE) issues that were discussed in the NRCs annual assessment letter dated March 3, 2006. In that letter, the NRC staff documented a SCWE substantive cross-cutting issue and stated the NRCs intention to continue to monitor progress in this area.

On February 23, 2006, and March 1, 2006, the inspectors conducted a sampling review of PSEGs SCWE metrics, or performance indicators (PIs), for fourth quarter 2005.

Documents reviewed are listed in the attachment.

b. Findings and Observations

No findings of significance were identified.

In fourth quarter 2005, PSEG identified twenty-one PIs as being green or satisfactory while eight PIs were identified as red or needing improvement. This was an improvement from the first quarter 2005, when there were seventeen green PIs and thirteen red PIs. A PI that monitored management attendance at SCWE training was eliminated because the training was completed.

4OA3 Event Followup

.1 (Closed) LER 05000354/2005-004-00, A Control Room Emergency Filtration (CREF)

Train Inoperable with B CREF Out of Service

a. Inspection Scope

On May 12, 2005, PSEG discovered the guide vane pivot arm for the 'A' control room chiller, 1AK400, slipped relative to the guide vane shaft. The 1AK400 chiller supplies chilled water to control room emergency filtration (CREF) system, vital switchgear room ventilation trains, and SACS pump room ventilation trains. The arm slippage affected the ability of the 1AK400 to reliably remove heat from the chilled water system. The 1BK400 chiller was out of service for scheduled maintenance activities during the time the 1AK400 was exhibiting vane pivot arm slippage. A follow-up operability assessment performed several weeks later concluded that with the guide vane pivot arm slippage, the1AK400 chiller was not capable of performing its design function of maintaining temperatures in the control room envelope during normal and accident conditions. A review of plant data determined that the guide vane slippage for the 1AK400 chiller most likely started at approximately 9:50 a.m. on May 9, 2005. The A CREF train was inoperable for approximately 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />. With the B CREF train inoperable during this same time period, Technical Specification (TS) 3.0.3 would have been applicable for having both trains of CREF inoperable. The inspectors reviewed the LER and associated evaluations. The enforcement action associated with the violation of Technical Specification 3.0.3 is described in Section 4OA7. This LER is closed.

b. Findings

Introduction:

A Green, self-revealing non-cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action," was identified when the guide vane pivot arm on the 1AK400 control room chiller was discovered to be operating incorrectly, rendering the chiller unable to perform its design function.

Description:

On May 20, 2004, PSEG discovered that the 'B' control room chiller, 1BK400, was not operating correctly. Specifically, the chiller evaporator pressure was higher (61 psig) than the required operating band of 35 to 50 psig. The chiller was declared inoperable. PSEG discovered the 1BK400 guide vane pivot arm was slipping on the drive shaft. PSEG determined that the chiller was not capable of performing its design function of maintaining temperatures within the control room envelope during normal operating and accident conditions.

PSEG performed an apparent cause evaluation under order 70039481. PSEG identified that improper assembly of the guide vane pivot arm led to the inoperability of the B CREF on May 20, 2004, and directed an apparent cause evaluation be performed in accordance with procedure NC.CA-TM.ZZ-0005(Z), Rev. 3, Apparent Cause Evaluation Guideline. PSEG documented that the improper assembly was due to inadequate engagement of setscrews on the guide vane shaft. PSEG determined that the setscrew engagement problem was due to inadequate procedural guidance. Specifically, the maintenance procedure used to overhaul the chiller, HC.MD-CM.GJ-0001(Q), Rev. 12, Water Chiller Unit & Compressor Overhaul, did not provide instructions to dimple the shaft. Dimpling the shaft required technicians to drill an indentation in the shaft where the setscrew would contact the shaft, improving the holding power of the setscrew.

PSEG noted, through review of industry operating experience, that other stations addressed similar setscrew engagement problems by dimpling the shaft.

PSEG corrective actions for the May 20, 2004, failure of 1BK400 included revising the chiller overhaul procedure to include dimpling of the guide vane shaft and providing post-maintenance testing criteria in existing maintenance items to include monitoring of evaporator pressure.

On May 12, 2005, PSEG discovered a related issue on the 'A' control room chiller. The guide vane arm slipped approximately 20 degrees on the 'A' control room chiller (1AK400) guide vane actuator shaft. PSEG declared the 1AK400 chiller inoperable at 9:50 p.m. and performed corrective maintenance under work order 60054534. PSEG determined from a review of plant data the 1AK400 chiller was likely inoperable from May 9, 2005, at 9:50 a.m. until May 12, 2005, at 10:53 p.m.

Maintenance technicians discovered the three setscrews holding the drive arm on the shaft were loose and two of the three setscrews in the vane actuating arm were also loose. Technicians also determined that thread adhesive was not present on the setscrews. Thread adhesives are compounds used to enhance mechanical joints to reduce the likelihood of threaded fasteners from loosening.

PSEG performed an apparent cause evaluation under order 70047411. PSEG determined that the failure of the 1AK400 chiller was due to loose setscrews on the guide vane pivot and actuating arms. PSEG determined the apparent cause was inadequate use of industry operating experience for setting setscrews. PSEG found that some common practices of minimizing loosening of threaded fasteners were not incorporated into station procedures, work orders, or maintenance training.

PSEG determined in order 70047411 that corrective actions from the evaluation of the failure of the 'B' control room chiller on May 20, 2004, were not adequately identified and added to maintenance procedures or work orders. Specifically, industry operating experience and standards were not used such that thread adhesives were not added to work order material lists and guidance to verify tightness or torque was not added to procedures. Also, the apparent cause evaluation documented in order 70039481 did not examine the extent of cause of improper assembly of a guide vane arm and shaft with setscrews as a locking device as it applied to the other arm and shaft assembly on the guide vane actuator that was in the same linkage assembly.

PSEG's corrective actions included modifying procedure SH.MD-GP.ZZ-0022, Bolt Torquing and Bolting Sequence Guidelines, and HC.MD-GP.ZZ-0245, Hope Creek Carrier Centrifugal Chiller Frequent & Periodic Inspections (Overhaul), to incorporate guidance contained in industry guidelines and utilize double verification of tightness or torque of fastener parts, and to incorporate the use of thread adhesives into appropriate maintenance procedures. PSEG also provided training to maintenance technicians qualified to perform assembly of arms and linkages.

Analysis:

Inspectors determined that the failure to correct deficiencies related to the improper assembly of guide vane linkages on the 1AK400 chiller guide vane arm linkages was a performance deficiency and a finding. PSEG did not perform an adequate apparent cause evaluation for the 'B' control room chiller, as documented in order 70039841, which led to the failure to identify conditions adverse to quality associated with maintenance practices on the guide vane actuator shaft joint assembly.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The improper installation of setscrews on the 1AK400 chiller guide vane arms resulted in the chiller not being able to perform its design function and unplanned unavailability of the chiller to implement repairs. The 1AK400 chiller was inoperable for approximately 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />. The inspectors completed a Phase 1 screening using Appendix A of Inspection Manual Chapter (IMC) 0609, Determining the Significance of Reactor Inspection Findings for At-Power Situations, and determined that the performance deficiency was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train greater than its technical specification allowed outage time, and did not screen as risk significant due to external events.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG failed to identify inadequate maintenance practices associated with the 'A' control room chiller guide vane arm linkages after the 'B' chiller failed in a similar manner on May 12, 2004. As a result, the A control room chiller was rendered unavailable for 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br /> on May 9, 2005. PSEG determined the apparent cause evaluation documented in order 70039481 did not identify relevant industry operating experience and industry practices related to setscrew installation and should have been incorporated into maintenance procedures or instructions for the guide vane actuator for the 'A' chiller. Because this finding is of very low significance and has been entered into PSEGs corrective action program in notifications 20238229, 20254263, and 20264705, this violation is being treated as an NCV, consistent with section VI.A.1 of the NRC Enforcement Policy: NCV 05000354/2006002-04, Inadequate Corrective Action Results in Unavailability of the 1AK400 Control Room Chiller.

.2 Unplanned Power Reduction on January 14, 2006

a. Inspection Scope

The inspectors responded to an unplanned power reduction on January 14, 2006. An electrical fault in non-vital 13kV bus-work related to the #4 station lighting transformer caused the loss of the offgas recombiner train. At 2:48 a.m., operators began a power reduction to 80% power in response to degrading main condenser vacuum due to the loss of the offgas system. High vibration alarms were received on the A and B reactor recirculation pumps in the control room during the power reduction. Operators reduced power to 71% in accordance with station alarm response procedures to clear the alarming condition. Power was reduced again to approximately 60% to perform planned control rod scram time testing. The inspectors discussed the transient with operators, engineers, and plant management to understand the occurrence and assess PSEGs evaluation of the cause and followup actions. The inspectors reviewed operator actions and station procedures to verify proper actions were taken and plant equipment responded as expected. The inspectors assessed PSEGs apparent cause determination and proposed corrective actions prior to power ascension. The inspectors later reviewed PSEGs root cause evaluation of the issue.

PSEG determined the cause of the electrical fault to be insulation breakdown due to conduction across a dislodged electrical bus insulating boot combined with a high moisture environment. PSEG determined that the original design of the non-safety related bus enclosure did not include heaters to control moisture and condensation.

PSEG also determined that the insulating boot likely fell off the bus duct due to improper or missing fasteners. PSEG corrective actions included inspecting other outdoor switchgear and panels for installation of space heaters and evidence of moisture-induced degradation, recommending to plant management installation of bus duct heaters for the non-safety related station lighting transformers, and installing insulating boots in accordance with vendor installation instructions.

b. Findings

No findings of significance were identified.

.3 Reactor Recirculation Pump Runback on February 4, 2006

The inspectors responded to a reactor recirculation pump runback on February 4, 2006.

During scheduled swapping of main generator stator water cooling (SWC) pumps, the A SWC pump breaker failed to close on the first attempt. Operators attempted to close the breaker again. The control room received a report of light smoke from the breaker and secured power to 125V bus 10B110. The loss of power to non-safety related bus 10B110 caused a loss of indication to the suction valve of the A primary condensate pump (PCP). The A PCP then tripped by design on an interlock that monitors the status of its suction valve. The loss of the A PCP caused a reactor recirculation runback by design that reduced reactor power from 100% to approximately 53% power.

The inspectors discussed the transient with operators, engineers, and plant management to understand the event and assess PSEGs evaluation of the cause and followup actions. The inspectors reviewed operator actions, station procedures, and plant response to verify proper actions were taken and plant equipment responded as expected. The inspectors assessed PSEGs apparent cause determination and proposed corrective actions prior to power ascension. The inspectors subsequently reviewed PSEGs apparent cause evaluation of the event and equipment issues.

PSEG determined the non-safety related control relay on the A SWC pump breaker to be the source of the smoke. No fire was observed. The breaker was shipped to the vendor for failure analysis. PSEG is tracking the failure analysis under order 70053837.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On April 3, 2006, the inspectors presented their overall findings to members of PSEG management led by Messrs. Barnes and Massaro. None of the information reviewed by the inspectors was considered proprietary.

On April 7, 2006, the inspectors met with Mr. Massaro to discuss a change in status of a finding presented at the exit meeting on April 3, 2006.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by PSEG and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as non-cited violations.

C Technical Specification (TS) 3.7.2 requires that two independent control room emergency filtration (CREF) system subsystems be operable. Contrary to the above requirement, PSEG identified that both the A and B trains of CREF were inoperable for approximately 83 hours9.606481e-4 days <br />0.0231 hours <br />1.372354e-4 weeks <br />3.15815e-5 months <br />, from May 9 through 12, 2005, due to the

'B' chiller being out of service for planned maintenance and the 'A' chiller being inoperable due to guide vane actuator slippage. The performance deficiency resulted in the 'A' CREF train being unavailable for 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br />. PSEG entered this issue into the corrective action program in notification 20238229. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase 1 SDP Screening and determined this finding to be of very low safety significance (Green). This finding screened to Green because the finding did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time. This event is described in LER 05000354/2005-004-00 and in Section 4OA3 of this report.

C 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Contrary to the above requirement, PSEG did not provide adequate work instructions for technicians to assemble a mechanical joint on the 1BK400 control room chiller vane actuator arm assembly. As a result, on December 8, 2005, the 1BK400 chiller guide vane actuator arm was found by equipment operators to be malfunctioning, resulting in the 1BK400 being declared inoperable and removed from service for repair. This was licensee-identified because an equipment operator observed this on a required round initiated to monitor for this potential problem. The 1BK400 chiller was unavailable for approximately 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> on December 8 and 9, 2005. PSEG entered the deficiency in their corrective action program under notification 20264293. In accordance with IMC 0609, Appendix A, this finding was of very low safety significance (Green), because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time, did not represent an actual loss of safety function of one or more non-Technical Specification Trains of risk significant equipment per 10CFR50.65, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and did not screen as potentially risk significant due to external events.

C 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that design changes, including field changes, shall be subject to design control measures commensurate with those applied to the original design. Contrary to the above requirement, PSEG replaced two valves in the safety auxiliaries cooling system (SACS) without ensuring they meet the design requirement of the valves being replaced. The two new valves were of a different design than the two replaced and their installation resulted in a different flow balance in the SACS. PSEG entered this issue into their corrective action program as notification 20271798. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase 1 SDP Screening and determined the finding to be of very low safety significance (Green). This finding screened to Green because the finding was a design deficiency confirmed not to result in loss of operability per Part 9900, Technical Guidance, Operability Determination Process for Operability and Functional Assessment.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

G. Barnes, Site Vice President

M. Massaro, Plant Manager

D. Benyak, Regulatory Assurance Director

J. Barstow, Licensing

M. Pfizenmaier, Senior Manager Plant Engineering

A. Shabazian, Maintenance Rule Coordinator

K. Knaide, Manager - Engineering Programs

A. Tramontana, NSSS Branch Manager

S. Afarian, HPCI System Engineer

J. Anthes, Service Water System Engineer

M. Kelly, Chilled Water System Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000354/2006002-02 URI RHR HX Flow Testing Methodology (Section 1R07.2)

Opened/Closed

05000354/2006002-01 NCV Failure to Implement Corrective Actions for Service Water Pump Packing (Section 1R07.1)

05000354/2006002-03 NCV (Section 1R12)

05000354/2006002-04 NCV Inadequate Corrective Action Results in Unavailability of the 1AK400 Control Room Chiller (Section 4OA3.1)

Closed

05000354/2005-004-00 LER A Control Room Emergency Filtration (CREF)

Train Inoperable with B CREF Out of Service (Section 4OA3.1)