IR 05000272/2005012

IR 05000354-05-007, 05000272-05-012, 05000311-05-012; 11/28/2005 - 12/16/2005; Hope Creek Nuclear Generating Station; Salem Nuclear Generating Station; Biennial Baseline Inspection of the Identification and Resolution of Problems

ML060260044
Person / Time
Site:	Salem, Hope Creek
Issue date:	01/26/2006
From:	Mel Gray Reactor Projects Branch 3
To:	Levis W Public Service Enterprise Group
Gray M, RI/DRP/Br3
References
IR-05-007, IR-05-012
Download: ML060260044 (30)

Text

ary 26, 2006

SUBJECT:

HOPE CREEK AND SALEM NUCLEAR GENERATING STATIONS - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000354/2005007, 05000272/2005012, AND 05000311/2005012

Dear Mr. Levis:

On December 16, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed a team inspection at the Hope Creek and Salem Nuclear Generating Stations. The enclosed inspection report documents the inspection findings, which were discussed with Mr. T. Joyce and other members of your staff at an exit meeting on December 16, 2005.

The inspection examined activities conducted under your license as they relate to the identification and resolution of problems, 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.

This inspection was conducted primarily for the purpose of assessing the problem identification and resolution (PI&R) program at Hope Creek, but was expanded to include site-wide PI&R activities, including Salem. This expanded scope was consistent with the implementation of the renewed Reactor Oversight Process Action Matrix Deviation Memorandum for Salem/Hope Creek dated July 29, 2005.

On the basis of the samples selected for review, the team concluded that, in general, problems were properly identified, evaluated, and corrected. The team determined that implementation of the corrective action program in the areas of Problem Identification and Effectiveness of Corrective Actions had improved since the Salem PI&R inspection, which was completed in March 2005. The team identified weaknesses in the area of Problem Evaluation, which was consistent with the results of your corrective action program self assessment.

There were three findings of very low safety significance (Green) associated with insufficient evaluation of degraded conditions. Two of the findings were attributed to Salem and one was for Hope Creek. These findings were determined to be violations of NRC requirements.

However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs)

consistent with Section VI.A of the NRCs 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, DC 20555-0001; with copies to the Regional Administrator, Region I; the

Mr. William Levis 2 Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspectors at Hope Creek and Salem Nuclear Generating Stations.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and 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 the 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, Acting Chief Projects Branch 3 Division of Reactor Projects Docket No: 50-354; 50-272; 50-311 License No: NPF-57; DPR-70; DPR-75

Enclosure:

Inspection Report 05000354/2005007; 05000272/2005012; 05000311/2005012 w/Attachment: Supplemental Information

REGION I==

Docket No: 50-354; 50-272; 50-311 License No: NPF-57; DPR-70; DPR-75 Report No: 05000354/2005007, 05000272/2005012, 05000311/2005012 Licensee: Public Service Enterprise Group (PSEG) Nuclear LLC Facility: Hope Creek Nuclear Generating Station Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: November 28 through December 16, 2005 Inspectors: B. Welling, Sr. Project Engineer, Team Leader J. Schoppy, Sr. Reactor Inspector G. Malone, Sr. Resident Inspector, Hope Creek A. Rosebrook, Project Engineer T. OHara, Reactor Inspector M. Patel, Reactor Inspector R. Bhatia, Reactor Inspector Approved By: Mel Gray, Acting Chief Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000354/2005007, 05000272/2005012, 05000311/2005012; 11/28/2005 - 12/16/2005;

Hope Creek Nuclear Generating Station; Salem Nuclear Generating Station; Biennial Baseline Inspection of the Identification and Resolution of Problems.

This inspection was conducted by regional inspectors and a resident inspector. Three Green findings were identified, all of which were non-cited violations. The significance of most findings is indicated by their color (Green, White, Yellow, 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.

Identification and Resolution of Problems The team concluded that, in general, PSEG was effective at identifying problems and entering them into the corrective action program. Issues were typically screened and prioritized in a timely manner using established criteria. Causal evaluations for significant issues and events were thorough. However, the team identified deficiencies in the evaluations of some less significant degraded conditions. The team determined that implementation of the corrective action program in the areas of Problem Identification and Effectiveness of Corrective Actions had improved since the Salem PI&R inspection, which was completed in March 2005. The team identified weaknesses in the area of Problem Evaluation, which was consistent with the results of PSEGs corrective action program self-assessment. There were three Green findings identified during this inspection. The findings involved insufficient evaluation of a high pressure coolant injection system minimum flow valve problem, a failure to properly evaluate and correct a degraded emergency diesel generator (EDG) service water inlet valve to ensure EDG operability, and failure to evaluate the effects of freon leaks on chiller availability and develop appropriate corrective actions. Additionally, the team identified examples of minor significance where PSEG did not enter conditions adverse to quality into the corrective action system or did not take timely or effective corrective actions. Audits and self-assessments were generally effective and identified adverse conditions and negative trends.

Cornerstone: Mitigating Systems

C

Green.

(Salem Unit 1) The team identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PSEG failed to properly evaluate and correct freon leaks on control area chillers. This condition resulted in a trip and unplanned unavailability of the '11' control area chiller.

PSEG entered this issue into the corrective action program.

The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone in that it reduced the availability of systems that respond to initiating events to prevent undesirable consequences. This issue also impacted the Initiating Events cornerstone ii

because unavailability of one chiller train increased the likelihood of loss of control area ventilation and loss of control air events. In accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the inspectors conducted a Phase 2 SDP evaluation and determined the issue to be of very low safety significance (Green). The performance deficiency had a problem identification and resolution cross-cutting aspect, in that previous evaluations were narrow in scope and did not include periodic monitoring of freon inventory to preclude repeat trips. (Section 4OA2.2)

C

Green.

(Salem Unit 1) The team identified an NCV of 10 CFR 50, Appendix B,

Criterion XVI, Corrective Action, for failure to properly evaluate and correct a known degraded condition on 12SW39, the service water stop valve to the 1B emergency diesel generator (EDG) jacket water and lube oil coolers. PSEG documented degraded operation of the 12SW39 valve in October 2004, when PSEG evaluated a similar failure of the 23SW39 valve to pass its surveillance stroke time test. On September 19, 2005, the 12SW39 valve failed to open causing the 1B EDG to be unavailable until operators opened the valve. PSEG entered this issue into the corrective action program.

The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Because the valve was demonstrated operable on September 18, 2005, the exposure time for the failure of 12SW39 was less than one day. 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 issue to be of very low safety significance (Green). 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 Technical Specification allowed outage time, and did not screen as potentially risk significant due to external events. The performance deficiency had a problem identification and resolution cross-cutting aspect, in that evaluation of the 12SW39 valve was incomplete and did not provide for adequate corrective actions. (Section 4OA2.2)

C

Green.

(Hope Creek) The team identified an NCV of 10 CFR 50, Appendix B,

Criterion XVI, Corrective Action, for failure to properly evaluate and correct a condition adverse to quality associated with the high pressure coolant injection (HPCI) system minimum flow valve. This condition was an improperly adjusted motor operated valve limit switch that allowed the minimum flow valve to open under test conditions, but still indicate shut. The anomaly with the minimum flow valve first occurred in January 2005, but it was insufficiently evaluated without any work performed. This problem led to unplanned unavailability of HPCI to troubleshoot and correct the limit switch problem when it repeated in September 2005. PSEG entered this issue into the corrective action program.

The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability iii of systems that respond to initiating events to prevent undesirable consequences. 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 issue to be of very low safety significance (Green). 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 Technical Specification allowed outage time, and did not screen as potentially risk significant due to external events. The performance deficiency had a problem identification and resolution cross-cutting aspect, in that engineering personnel missed a prior opportunity to identify the incorrectly set limit switch in January 2005. (Section 4OA2.2)iv

REPORT DETAILS

4OA2 Identification and Resolution of Problems (Biennial - 71152B)

Effectiveness of Problem Identification

a. Inspection Scope

The inspection team reviewed the procedures describing PSEGs corrective action program. PSEG identifies problems by initiating notifications (NOTFs) for conditions adverse to quality, equipment deficiencies and non-conformances, human performance problems, industrial or radiological safety concerns, and other significant issues. The NOTFs are subsequently screened for operability, categorized by priority and significance, and assigned for evaluation and resolution.

The team reviewed NOTFs selected across the seven cornerstones of safety in the NRC Reactor Oversight Process (ROP) to determine whether PSEG was appropriately identifying, characterizing, and entering problems into the corrective action program.

Team members chose items from PSEGs maintenance, operations, engineering, emergency planning, security, radiological controls, training, and oversight programs to verify that PSEG appropriately considered problems identified in each functional area.

In addition to NOTFs, the team selected items from other processes at Hope Creek and Salem to verify that PSEG appropriately considered problems identified in these processes for entry into the corrective action program (CAP). Specifically, the team reviewed a sample of operator log entries, control room deficiency and work-around lists, operability determinations, engineering system health reports, completed surveillance tests, and maintenance orders. The documents were reviewed to ensure that problems were appropriately considered for resolution via the CAP. In addition, the team interviewed plant staff and management personnel to determine their understanding of and involvement in the CAP. A list of NOTFs and documents reviewed, and a list of key personnel contacted, are provided in the Attachment to this report.

The team reviewed a sample of PSEGs Quality Assessment/Nuclear Oversight audits, CAP self-assessments, and departmental self-assessments. This review was performed to determine if problems identified through these processes were entered into the CAP. The effectiveness of the audits and self-assessments was evaluated by comparing the results with self-revealing and NRC-identified findings, and observations during the inspection.

The team considered risk insights from the NRCs and PSEGs risk analyses to focus the sample selection and plant tours on risk-significant components. The team selected the high pressure coolant injection, emergency diesel generator, residual heat removal, 4 KV, and 125 VDC systems for in-depth review.

On July 29, 2005, the NRCs Executive Director for Operations renewed a deviation from the NRCs ROP Action Matrix to provide a greater level of oversight for the Salem and Hope Creek stations than would typically be called for by the Action Matrix. In accordance with this deviation, the Hope Creek inspection team was augmented with additional inspectors and the scope of the review was expanded to include site-wide PI&R activities and additional NOTFs.

b. Findings

and Assessments No findings of significance were identified in the area of Problem Identification.

The team determined that PSEG was generally effective at problem identification at Hope Creek and Salem. The station staff had appropriate knowledge of the CAP and entered identified problems into the program at a low threshold. There were approximately 23,000 NOTFs initiated from January to November 2005. Station staff promptly initiated NOTFs, as appropriate, in response to deficiencies or issues raised by the inspection team.

Quality Assessment (QA) audits and self-assessments identified adverse conditions and negative trends. They were generally self-critical and consistent with the teams findings.

The team identified some examples where PSEG did not enter conditions adverse to quality into the CAP and did not identify and correct other minor deficiencies in a timely manner. Some of these issues included (NOTF numbers in parentheses):

C Oil leak on 'B residual heat removal pump (Hope Creek). (20263133)

C Questionable thread engagement on '11' auxiliary feedwater (AFW) pump packing studs. (20263095)

C Seismic retaining clips for safety-related instrument air tubing were found missing in 3 locations of the 5 checked in Salem Units 1&2 84' Elevation.

(20263354, 20263356, 20263357)

The team also observed that the use of equipment malfunction information system (EMIS) tags was inconsistent. During plant walkdowns, the team identified several EMIS tags hanging that should have been removed following corrective maintenance (20204768, 20237698, 20061921, 20152783, 20242745, 20250152, and others). EMIS tags left hanging after work completion potentially mask the degraded condition should it recur. Alternately, the team noted examples where previously identified deficiencies did not have EMIS tags applied (20256258). These EMIS tag deficiencies represent a recurring CAP weakness based upon previous NRC PI&R inspection observations at Salem and Hope Creek. Corrective actions for these observations during the Salem PI&R inspection (NRC inspection report 05000272;311/2005007 and 05000354/2005006; February - March 2005) did not resolve the problem. PSEG initiated NOTF 20263482 to address this repeat issue.

The team independently evaluated the problem identification deficiencies noted above for potential significance. The team determined that none of the individual issues were of more than minor significance because they did not result in a challenge to system availability or reliability. However, these NRC-identified issues indicated an area for improvement in PSEG problem identification.

2. Prioritization and Evaluation of Issues

a. Inspection Scope

The team reviewed the NOTFs listed in the Attachment to this report to assess whether PSEG adequately prioritized and evaluated problems. The team selected NOTFs to cover the seven cornerstones of safety identified in the NRC ROP. The review was expanded to five years for NOTFs on issues in the inservice inspection program and service water system that were age dependent.

The NOTFs encompassed the full range of PSEG evaluations, including root cause, apparent cause, common cause, and simple evaluations. The review included the appropriateness of the assigned significance, the timeliness of resolutions, and the scope and depth of the causal analyses. For significant conditions adverse to quality, the team reviewed PSEGs corrective actions to prevent recurrence. The team also reviewed PSEGs evaluations of industry operating experience information for applicability to their facility.

The team attended PSEG's Initial Screening Committee and Management Screening Committee meetings to observe the review process and to understand the bases for assigned significance levels (i.e., SL 1, 2, or 3). The team also reviewed PSEGs equipment operability determinations, reportability assessments, and extent-of-condition reviews for selected problems and degraded conditions. Additionally, the team reviewed equipment performance results and evaluations documented in completed surveillance test procedures and operator log entries to determine whether the evaluations were technically adequate to identify degrading or non-conforming equipment.

b. Findings

and Assessments There were three Green non-cited violations identified during this inspection involving inadequate evaluation of degraded conditions.

The team determined that, in general, PSEG adequately prioritized and evaluated the issues and concerns entered into the CAP. However, the team noted weaknesses in PSEGs evaluation of degraded conditions. The results of high level evaluations, such as root cause analyses were typically thorough; however, the teams review of lower level evaluations revealed some aspects that were incomplete or less than thorough.

Personnel were generally effective at classifying and performing operability evaluations and reportability determinations for degraded conditions. Notwithstanding, the team identified instances in which PSEG did not adequately perform operability evaluations or did not do so in a timely manner. These involved (NOTF numbers in parentheses):

C Clogged reactor building floor drains at Hope Creek. (20216883 & 20249085)

C Degraded condition of 12SW39, the service water stop valve to the 1B emergency diesel generator (EDG) jacket water and lube oil coolers. This issue is described in the finding below. (Salem)

C For the Salem '13' auxiliary feedwater pump enclosure damper 1ABS4, the loss of a licensing basis emergency function for the damper to close on a high pressure steam line break was identified, but engineering personnel did not fully evaluate the impact of this degraded condition on the operability of nearby safety-related equipment. Also, the impact of the described failure mechanism was not properly considered in re-evaluations. (20255139, 20263228)

C Leakage past the 1CV52 check valve for the '12' charging pump and impact on safety injection flow rate. (Salem) (20257289)

C Foreign material in the torus and impact on emergency core cooling systems.

(Hope Creek) (20264863)

The team also noted that some of the apparent cause evaluations, simple evaluations, and reviews of issues related to risk-significant components and systems were incomplete, not well-documented, or less than thorough. Examples included:

C Control rod drive pump room floor plug seal potential flooding impact on core spray pumps. (Hope Creek) (70046707)

C Service water system grassing impact. (Hope Creek) (20265123 & 20263699);

C Extent-of-condition regarding loose bolts identified during a system walkdown of the Hope Creek Class 1E 4 kV system. (20249172);

C Impact of a clogged station service water strainer vent line (Hope Creek)

(20255120, 20264599).

C Repeat test failures of the reactor building to torus vacuum breaker and associated pressure buildup between inboard and outboard valves. (Hope Creek) (20263191, 20255217, 20251483).

The team observed that station personnel missed opportunities to more definitively identify failure mechanisms on risk-important components because the parts were not analyzed before disposal. For example:

• The Salem 12SW39 valve was not examined for failure mode.

• The Salem 1ABS4 damper solenoid and damper were disposed of prior to establishing a failure mechanism.

• Foreign material in the reactor core isolation cooling system was not analyzed.

(Hope Creek)

The team noted that root cause evaluations were generally complete. The root cause methodology was typically identified in the evaluations.

The team independently evaluated the CAP deficiencies noted above for potential significance. The team determined that none of the individual issues were of more than minor significance because they did not result in a challenge to system availability or reliability. However, these issues represented examples where the corrective actions for identified conditions were not adequately prioritized and evaluated.

.1 Control Area Chiller Trips Due to Failure to Identify Freon Leaks

Introduction:

The team identified a Green non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, in that control area chiller system freon leaks were not promptly evaluated and corrected, which resulted in a trip and unavailability of the '11' control area chiller.

Description:

On November 11, 2005, the Salem Unit 1 control area chiller number '11' tripped on a freeze protection signal. Following the trip, technicians discovered freon leaks from two test connections used for periodic diagnostic testing of the chillers. The chiller control system monitors for low suction pressure and low chilled water temperature that can indicate the potential for freezing of heat exchanger tubes. The leaking freon caused compressor suction pressure to decrease until the chiller tripped on a freeze protection signal. PSEGs evaluation determined that there were component monitoring deficiencies that failed to detect early degradation. Specifically, there were no processes in place to periodically monitor the control area chillers to verify proper freon inventory or identify freon leaks. Corrective actions identified in the evaluation included the creation of a monthly preventative maintenance task to check chillers for freon leakage.

A similar event occurred on May 10, 2005, when the Salem Unit 2 control area chiller number 22 tripped on freeze protection. PSEGs evaluation of the trip in May 2005, determined that a slow freon leak in the fittings on a liquid line solenoid valve led to a low suction pressure freeze protection trip. The evaluation documented four additional instances of freon leaks on other control area chillers in 2004 that resulted in unplanned chiller shutdowns or trips. The evaluations and corrective actions for the May 10, 2005, trip and the trips in 2004 were narrow in scope, in that they involved replacing or fixing the leaking components and did not include periodic monitoring of freon inventory to preclude repeat trips.

Analysis:

PSEG did not properly evaluate, and correct freon leaks in May 2005, and in 2004, which led to a trip of the '11' control area chiller. This constitutes a performance deficiency. The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone in that it reduced the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The chilled water system is listed as a mitigating system in Table 2 of the Risk Informed Inspection Notebook for Salem Generating Station, Revision 2, and provides support and cooling for the control area ventilation system and the emergency control air compressors. This issue also impacted the Initiating Events cornerstone because unavailability of one chiller train increased the likelihood of loss of control area ventilation and loss of control air events. 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 a more detailed Phase 2 evaluation was required to assess the safety significance because the finding affected two cornerstones (Initiating Events and Mitigating Systems).

The inspectors conducted a Phase 2 evaluation, using the Loss of Control Area Ventilation (LCAV) and Loss of Control Air (LCA) worksheets from Revision 2 of the Risk Informed Inspection Notebook for Salem Generating Station, and concluded that the finding was of very low safety significance (Green). The SDP Phase 2 evaluation used the following assumptions:

C An exposure time of less than three days; and C The initiating event likelihood for LCAV and LCA was increased by one order of magnitude consistent with Rule 1.2 of IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations.

The loss of control area ventilation core damage sequence was the most dominant core damage sequence and was mitigated by operator actions that established alternate ventilation and shut down the plant using the remote shutdown system. The performance deficiency had a problem identification and resolution cross-cutting aspect, in that previous evaluations were narrow in scope and did not include periodic monitoring of freon inventory to preclude repeat trips.

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 did not adequately monitor freon inventory to promptly identify and correct slow freon leaks on the '11' control area chiller, prior to a trip on November 11, 2005, even though similar chiller trips had occurred five times since 2004 for similar freon leaks. Because this finding is of very low safety significance and has been entered into the corrective action program as notification 20260955, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy. (NCV 05000272/2005012-01, Freon Leaks on

'11' Control Area Chiller)

.2 Failure of Salem 12SW39 Valve Rendered 1B Emergency Diesel Generator Unavailable

Introduction:

The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, in that PSEG did not properly evaluate and correct a degraded condition on Salem valve 12SW39, the service water stop valve to the 1B emergency diesel generator (EDG) jacket water and lube oil coolers. The failure of this valve resulted in unavailability of the 1B EDG.

Description:

In October 2004, PSEG documented degraded operation of the 12SW39 valve as part of an evaluation of another, similar valve (23SW39) failing to pass its surveillance stroke time test. Specifically, PSEG noted that the 12SW39 valve passed its stroke time test but stalled at 30-50% open, then traveled full open.

The 12SW39 valve's corresponding valve on the 2C EDG, 23SW39, failed to meet its stroke time requirement in October 2004 and was replaced. The SW39 valves have a safety function to open to admit cooling water to the EDG lube oil and jacket water coolers. The 23SW39 valve had stroked successfully on its previous five surveillance tests since its initial installation in September 2003. When the valve failed its stroke test in October 2004, its behavior (similar to 12SW39) was described as erratic, momentarily stalling in mid-stroke and then traveling full open.

PSEGs inspection of the 23SW39 valve revealed indications of galling or rubbing between the valve body, stem nut, gland ring, and stem. The galling or rubbing was determined to be from misalignment between the actuator and valve. This particular valve design did not include alignment pins between the actuator, the mounting plate, and the valve body. PSEG determined that if not properly aligned, the actuator can generate a force on the valve stem and cause damage. PSEG engineers stated the misalignment could impact valve stroke times and the ability of the valve to open.

PSEG issued an operability evaluation (CROD 04-024, 70041840) that determined that the SW39 valves on the EDGs were operable but degraded because the valves had been passing their surveillance test stroke times. Notably, the operability determination stated that the 12SW39 passed its stroke time test but stalled at 30-50% open, then traveled full open. The CROD established a plan to monitor the stroke times of the affected SW39 valves by changing the surveillance periodicity for the valve from quarterly to monthly and having an engineer, if practical, monitor the valve stroke. If the valve exceeded the acceptable stroke time range limit, or if the valve stroked twice in the required evaluation range, the valve would be declared inoperable, and a temporary modification would be used to maintain the valve in an open position.

On September 19, 2005, the 1B EDG was started for a surveillance test. Operators in the control room were informed that the 12SW39 valve did not indicate open after a period of 17 seconds. Field operators verified that the valve was closed and the 1B EDG was subsequently shutdown. PSEG performed a simple evaluation per procedure NC.WM-AP.ZZ-0002, Corrective Action Process. PSEG did not quarantine the valve nor attempt to determine the failure mode. The evaluation identified past problems with valve binding as described in the evaluation performed following the failure of the 23SW39 valve. The corrective actions for the 12SW39 valve failure were to replace the valve with a valve of new design that did not have the misalignment issues.

The team determined that the evaluation performed by PSEG for the 23SW39 failure in October 2004, which included the description of the degraded operation of 12SW39, was incomplete and as a result did not provide for adequate corrective actions. PSEG did not fully evaluate the failure mechanism of the 12SW39 valve and provide for timely response. The CROD provided for monitoring and action only during the surveillance tests and did not specify actions to be taken should the valve fail during an actual demand. Operations personnel determined that control room operators would not know that the 12SW39 valve failed to open on an actual demand until a high temperature alarm actuated for high lube oil or high jacket water temperature. PSEG had data that predicted a loaded EDG could operate without cooling water for a period of 5-8 minutes from EDG start before a high temperature alarm actuated. However, PSEG did not evaluate the failure mechanism and response times with respect to an actual demand, such as during a loss of offsite power, when the failure may not be known until an alarm condition occurred.

Analysis:

The team determined the failure to properly evaluate the degraded condition of valve 12SW39 was a performance deficiency. The finding was more than minor because the failure of valve 12SW39 to open caused unavailability of the 1B EDG and affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Because the valve was demonstrated operable on September 18, 2005, the exposure time for the failure mechanism on valve 12SW39 was less than one day. 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 issue to be of very low safety significance (Green). 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 Technical Specification allowed outage time, and did not screen as potentially risk significant due to external events. The performance deficiency had a problem identification and resolution cross-cutting aspect, in that evaluation of the 12SW39 valve was incomplete and did not provide for adequate corrective actions.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG did not promptly correct a condition adverse to quality associated with valve 12SW39 that led to its failure to open on September 19, 2005. The failure of valve 12SW39 rendered the 1B EDG unavailable. Because this finding is of very low safety significance and has been entered into the corrective action program as notification 20267341, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy.

(NCV 05000272/2005012-02, Failure of 12SW39 Rendered 1B Emergency Diesel Generator Unavailable)

.3 High Pressure Coolant Injection System Minimum Flow Valve Degraded Condition

Introduction:

The team identified a NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for failure to identify and correct a condition adverse to quality associated with the high pressure coolant injection (HPCI) minimum flow valve, which led to unplanned unavailability of the HPCI system.

Description:

On January 20, 2005, following governor testing of the Hope Creek HPCI system, operators observed that the torus water level was unexpectedly increasing.

During the course of troubleshooting this problem, operators cycled the HPCI minimum flow valve (F012) and the level rise ceased. Station personnel concluded that the F012 valve was leaking by, allowing water to flow from the condensate storage tank to the torus. NOTF 20220743 was initiated for corrective maintenance on the F012 valve.

Subsequently, on January 24, 2005, operations personnel initiated NOTF 20221030, which questioned the basis for operability of the HPCI system, given the anomalous behavior of the F012 valve. They were concerned that a partially open F012 valve would divert HPCI injection if called upon to perform its safety function. Engineering personnel performed evaluations in support of both NOTFs. Engineers determined that the valve opened partially during the test, even though the valve indicated shut, and they attributed the problem to the specific test conditions for the governor tuning test.

However, despite the question on operability, the evaluations did not lead to corrective maintenance, diagnostic testing of the F012 motor operated valve, or a full investigation into the cause of the malfunction. Both NOTFs were closed with no work performed on the F012 valve.

On September 16, 2005, during surveillance testing, the HPCI system failed to meet test pressure acceptance criteria. Also, as occurred in January 2005, the torus water level continued to rise after the test was completed, and the F012 valve was found partially open. Troubleshooting and investigation following this occurrence revealed an incorrectly set limit switch on the F012 motor operated valve. The incorrectly set limit switch allowed the valve to remain partially open even though it indicated shut.

Engineering personnel also concluded that the limit switch problem should have been detected during diagnostic testing prior to the January 2005 test.

Engineering personnel determined that the incorrectly set limit switch did not affect the safety function of HPCI, because under an automatic or manual initiation, the F012 valve would receive a seal-in signal to fully open and fully shut. However, under testing conditions, the valve may or may not receive the seal-in signal, and the incorrectly set limit switch would allow the valve to remain partially open, but indicate shut.

The inspection team concluded that the F012 valve malfunction was insufficiently evaluated in January 2005. Engineers incorrectly assumed that the valve behavior was due to governor test conditions and did not perform testing, corrective maintenance, or causal investigation. Consequently, engineering personnel missed an opportunity to identify the incorrectly set limit switch in January 2005. The insufficient evaluation led to unplanned unavailability of the HPCI system in September 2005, to troubleshoot and correct the limit switch problem.

Analysis:

PSEG did not properly evaluate and correct an observed degraded condition of the HPCI minimum flow valve in January 2005, which constitutes a performance deficiency. The insufficient evaluation led to unplanned unavailability of the HPCI system in September 2005, to troubleshoot and correct the limit switch problem, when the malfunction repeated. This finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. 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 issue to be of very low safety significance (Green). 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 Technical Specification allowed outage time, and did not screen as potentially risk significant due to external events. The performance deficiency had a problem identification and resolution cross-cutting aspect, in that engineering personnel missed a prior opportunity to identify the incorrectly set limit switch in January 2005.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG did not promptly identify and correct a condition adverse to quality associated with the HPCI minimum flow valve when a malfunction anomaly was first observed in January 2005. Because this finding is of very low safety significance and has been entered into the corrective action program as notifications 20264759, 20253009, and 20254514, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy. (NCV 05000354/2005007-03, High Pressure Coolant Injection Minimum Flow Valve Degraded Condition)

3. Effectiveness of Corrective Actions

a. Inspection Scope

The team reviewed the corrective actions associated with selected NOTFs to determine whether the actions addressed the identified causes of the problems. The team reviewed NOTFs for repetitive problems to determine whether previous corrective actions were effective. The team also reviewed PSEGs timeliness in implementing corrective actions and their effectiveness in preventing recurrence of significant conditions adverse to quality. In addition, the team reviewed NOTFs associated with selected NCVs and findings, to determine whether PSEG properly evaluated and resolved these issues. Furthermore, the team assessed the backlog of corrective actions to determine, if any, individually or collectively, represented an increased plant risk due to the delay in implementation.

b. Findings

and Assessments Overall, the team determined that corrective actions were completed in a timely manner and implemented as intended. The team observed that stricter administrative controls were put in place to ensure corrective actions are completed as scheduled and actions are properly implemented. In most cases, the team found that corrective actions were appropriate, effective, and completed in a timely manner. The team noted that there were fewer repeat issues than identified in previous NRC PI&R inspections at Salem and Hope Creek. However, the team observed some instances in which corrective actions did not appear to be effective or timely in addressing conditions adverse to quality. Examples included:

• Repetitive problems with EMIS tag usage, as described in Section 4OA2.1 of this report.

• Repeat flooding of Hope Creek valve pit no. 2, due to ineffective corrective actions. This valve pit contains non-safety related cold weather protection features for service water. (20263311)

• Several service water valve failures on containment fan cooler units. (Salem)

• Corrective actions for a high pressure coolant injection system oscillation problem did not include revising the applicable maintenance procedure. (Hope Creek) (20263227)

For NRC non-cited violations (NCVs) and findings, the team noted instances in which PSEG did not adequately evaluate or address the performance deficiencies associated with these NCVs. This is a repetitive observation from the Salem PI&R inspection (February - March 2005). Corrective actions for these observations did not resolve the issue. PSEG initiated NOTFs 20264465 and 20265676 to address this repeat issue.

PSEGs CAP self-assessment documented a similar observation. Examples included:

• Repeated challenges to standby service water pumps due to silting documented in NCV 354/2005006-07. (20265676)

• Degraded control rod drive (CRD) pump room flood barrier and drains documented in NCV 354/2005002-01. (20263789)

• Failure of Salem auxiliary feedwater system valve 1MS132 documented in NCV 272/2004003-06. (20264465)

The team independently evaluated the CAP deficiencies noted above for potential significance. The team determined that none of the individual issues were of more than minor significance because they did not result in a challenge to system availability or reliability. However, these issues represented examples where the corrective actions for identified conditions were not fully effective.

4. Assessment of Safety Conscious Work Environment

a. Inspection Scope

Team members interviewed plant staff, observed various activities throughout the plant, reviewed selected NOTFs, and attended a cross section of meetings to determine if conditions existed that would result in personnel being hesitant to raise safety concerns to their management and/or the NRC. The team also reviewed the Employee Concerns Program.

b. Findings

and Assessments No findings of significance were identified.

4OA6 Meetings, Including Exit

The team presented the inspection results to Mr. T. Joyce and other members of PSEG management on December 16, 2005. PSEG management acknowledged the results presented. No proprietary information was identified during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

G. Barnes, Hope Creek Station Vice President

J. Barstow, Corrective Action Program Manager

D. Benyak, Regulatory Assurance Director

J. DeFebo, Hope Creek Nuclear Oversight Manager

C. Fricker, Salem Plant Manager

T. Gierich, Salem Operations Director

H. Hanson, Hope Creek Operations Director

M. Jesse, Hope Creek Regulatory Assurance Manager

S. Jones, Employee Concerns Program

T. Joyce, Salem Station Vice President

S. Mannon, Salem Regulatory Assurance Manager

M. Massaro, Hope Creek Plant Manager

W. Mattingly, Salem Nuclear Oversight Manager

J. Perry, Hope Creek Maintenance Manager

D. Romashko, Nuclear Oversight Director

B. Thomas, Sr. Licensing Engineer

J. Williams, Hope Creek Engineering Director

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

05000272/2005012-01 NCV Freon Leaks on '11' Control Area Chiller (Section 4OA2.2)

05000272/2005012-02 NCV Failure of 12SW39 Rendered 1B Emergency Diesel Generator Unavailable (Section 4OA2.2)

05000354/2005007-03 NCV High Pressure Coolant Injection Minimum Flow Valve Degraded Condition (Section 4OA2.2)