IR 05000354/2003007

IR 05000354-03-007; 11/17 - 11/21 and 12/8 - 12/12/03; Hope Creek Generating Station; Biennial Baseline Inspection of the Identification and Resolution of Problems; Identification and Resolution of Problems

ML040270021
Person / Time
Site:	Hope Creek
Issue date:	01/26/2004
From:	Ray Lorson Division of Reactor Safety I
To:	Richard Anderson Public Service Enterprise Group
References
IR-03-007
Download: ML040270021 (26)

Text

ary 26, 2004

SUBJECT:

HOPE CREEK NUCLEAR GENERATING STATION - NRC INSPECTION REPORT 05000354/2003007

Dear Mr. Anderson:

On December 12, 2003, the NRC completed a team inspection at the Hope Creek Nuclear Generating Station. The enclosed report documents the inspection findings which were discussed on December 12 with Mr. John Carlin, Mr. Dave Garchow, Mr. Jim Hutton and other members of your staff during an exit meeting.

This inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, and compliance with the Commissions rules and regulations and the conditions of your operating license. Within these areas, the inspection involved examination of selected procedures and representative records, observation of activities, and interviews with personnel.

On the basis of the samples selected for review, the team concluded that in general, problems were properly identified, evaluated, and corrected. However, the teams findings supported the conclusion in the Annual Assessment Letter (NRC Inspection Report 50-354/2003-01) of the existence of a substantive cross cutting issue in the problem identification and resolution area.

There were three Green findings identified during this inspection associated with failure to implement adequate corrective actions. The findings involved poor prioritization and evaluation of an electro-hydraulic control oil leak, untimely resolution of residual heat removal minimum flow valve issues, and inadequate corrective actions for a control room chiller deficiency. Two of the findings were determined to be violations of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating these two findings as non-cited violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these non-cited violations, you should provide a response with the basis for your denial within 30 days of the date of this inspection report, to the U. S. Nuclear Regulator Commission, ATTN. Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U. S. Nuclear Regulator Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Hope Creek Facility.

Mr. Roy Anderson 2 In addition, several examples of minor problems were identified; including conditions adverse to quality that were not entered into the corrective action program, narrowly focused condition report evaluations; and corrective actions that were ineffectively tracked or not performed.

In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Raymond K. Lorson, Chief Performance Evaluation Branch Division of Reactor Safety Docket No: 50-354 License No: NPF-57

Enclosure:

Inspection Report 05000354/2003007 w/Attachment: Supplemental Information

REGION I==

Docket Nos: 50-354 License Nos: NPF-57 Report No: 05000354/2003007 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Hope Creek Nuclear Generating Station Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: November 17-21 and December 8-12, 2003 Inspectors: Joe Schoppy, DRS, Senior Reactor Inspector (Team Leader)

Ram Bhatia, DRS, Reactor Inspector Marc Ferdas, DRP, Resident Inspector Steve Pindale, DRS, Senior Reactor Inspector Josephine Talieri, DRS, Reactor Inspector Approved by: Raymond K. Lorson, Chief Performance Evaluation Branch Division of Reactor Safety

SUMMARY OF FINDINGS IR 05000354/2003-007; 11/17 - 11/21 and 12/8 - 12/12/03; Hope Creek Generating Station; biennial baseline inspection of the identification and resolution of problems; identification and resolution of problems.

This inspection was conducted by four regional inspectors and a resident inspector. The inspection identified three Green findings, two of which were also 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, problems were properly identified, evaluated, and corrected. However, the teams findings supported the conclusion in the Annual Assessment Letter (NRC Inspection Report 50-354/2003-01) of the existence of a substantive cross cutting issue in the problem identification and resolution (PI&R) area. Specifically, the team identified weaknesses in the evaluation and resolution of degraded conditions, documentation of actions, and the completion of identified corrective actions. There were three Green findings identified during this inspection associated with failure to implement adequate corrective actions. The findings involved poor prioritization and evaluation of an electro-hydraulic control (EHC) oil leak, improper resolution of residual heat removal (RHR) minimum flow valve issues, and inadequate follow through of a control room chiller deficiency. Additionally, the team identified examples where PSEG did not enter conditions adverse to quality into the corrective action system or did not properly classify the significance of an issue. Audits and self-assessments were generally effective and identified adverse conditions and negative trends.

A. NRC Identified and Self-Revealing Findings Cornerstone: Initiating Events

• Green. PSEG failed to promptly evaluate and correct deficiencies associated with the No. 4 combined intermediate valve (CIV) actuator resulting in an operational transient (manual reactor scram).

This self-revealing finding did not represent a violation of NRC regulatory requirements, in that the performance deficiencies occurred on a nonsafety-related system. The finding is greater then minor because it had an actual impact on plant stability as it caused a manual reactor scram. The finding is of very low safety significance (Green) because, although it caused a reactor scram it did not contribute to a primary or secondary system loss of coolant accident initiator, did not contribute to a loss of mitigation equipment functions, and did ii

not increase the likelihood of a fire or internal/external flood. (Section 4OA2.b.2.1)

Cornerstone: Mitigating Systems

• Green. The team identified a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for PSEGs failure to promptly address conditions adverse to quality concerning RHR minimum flow valve undesired cycling during RHR pump starts and erroneous RHR trip unit signals.

The finding was more than minor because it potentially affected the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events (i.e., loss of coolant accidents). The finding was associated with the attribute of equipment performance (RHR system availability and reliability). The finding was of very low safety significance (Green), because the problems did not result in a loss of the RHR system function. (Section 4OA2.c.2.1)

• Green. PSEG failed to adequately implement identified corrective actions for a B control area chiller problem which resulted in a subsequent chiller trip when operators placed it in service.

The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for this performance deficiency. This self-revealing finding was considered to be more than minor because it affected the Mitigating System cornerstone and was associated with the availability and reliability of the control area chiller. The finding was reviewed using a Phase 3 analysis and determined to be of very low risk significance based on reasonable assumptions which indicated the predicted increase in the core damage frequency (CDF) was negligible. (Section 4OA2.c.2.2)

B. Licensee-Identified Violations The team reviewed a violation of very low significance which was identified by PSEG.

Corrective actions taken or planned by PSEG have been entered into PSEGs corrective action program. The violation and corrective action tracking number is listed in Section 40A7 of this report.

iii

Report Details 4. OTHER ACTIVITIES (OA)

4OA2 Problem Identification and Resolution a. Effectiveness of Problem Identification (1) Inspection Scope The team reviewed PSEGs corrective action program and noted that problems were formally identified through the initiation of notifications (NOTFs). Team members attended the daily management meeting, where NOTFs were reviewed for screening and assignment, to understand the threshold for identifying problems and to assess management involvement with the corrective action process.

The team reviewed selected NOTFs to determine whether PSEG was appropriately identifying, characterizing, and entering problems into the corrective action process.

The team reviewed NOTFs initiated subsequent to the last NRC problem identification inspection that was completed in March 2001. The team selected NOTFs to cover the seven cornerstones of safety identified in the NRC Reactor Oversight Process (ROP).

In addition, the team considered risk insights from the individual plant examination (IPE)

report and the probabilistic risk assessment (PRA) to focus the NOTF sample selection and system walkdowns on risk significant components. The team used a vertical slice approach to perform a risk-informed review of PSEGs corrective actions related to the reactor core isolation cooling (RCIC), RHR, and 1E 250 Vdc systems. Attachment 1 lists the NOTFs selected for review.

The team also interviewed selected plant staff to determine whether personnel were familiar with and utilized the corrective action program to identify problems. The team conducted walkdowns of control room panels and selected plant equipment, including the drywell; attended operations turnover meetings; and toured the plant with several equipment operators (EOs) to independently assess whether problems were being adequately identified and addressed.

The team selected items from PSEGs maintenance, operations, engineering, and oversight processes to verify that PSEG appropriately considered problems identified in these processes for entry into the corrective action program. 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 (STs), maintenance orders, quality assessment (QA) reports, and departmental self-assessments. The team reviewed issues identified in these documents to ensure that underlying problems associated with each issue were appropriately evaluated and resolved.

(2) Observations and Findings No findings of significance were identified.

The team determined that, in general, PSEG adequately identified discrepant conditions and initiated NOTFs where appropriate. However, the team identified several examples where PSEG did not enter conditions adverse to quality into the corrective action system and did not identify and correct other minor deficiencies in a timely manner. In response to the teams observations during the initial walkdowns of the auxiliary/control building, service water (SW) intake structure, reactor building, protected area, and drywell; PSEG initiated 15 NOTFs and corrected an additional 17 minor plant deficiencies on the spot.

Some of these issues included:

C A minor steam leak from an insulated retired-in-place pipe in the A RHR heat exchanger room. The leak was on the high pressure coolant injection (HPCI)

side of a blank flange that isolated HPCI from A RHR (originally designed for the steam condensing mode of RHR). (NOTF 20167454)

C An unauthorized and unanalyzed filter found on the inlet to one of the two redundant room coolers in the A RHR pump room. (NOTF 20167689)

C Housekeeping and cleanliness problems in the drywell. The team identified various sections of loose or damaged insulation, an excessive amount of red tape in use, and assorted items of debris throughout all levels. (NOTFs 20170973, 20169993, 20169778, and 20170031)

C A valid low level condition on the G fuel oil storage tank (one of the two tanks that together supply the D emergency diesel generator (EDG)). The operators were aware of the condition and allowed it to exist for at least 12 days (November 5-17, 2003). The team noted that the comparatively large number of issues at the EDG local alarm panels (9 annunciators in solid and 19 equipment malfunction information system (EMIS) tags total for all four EDGs)

may have reduced operators sensitivity to this off-normal condition. On November 5, operators verified the combined fuel oil level satisfied the Technical Specification (TS) minimum level for the D EDG. (NOTF 20167601)

C Water leaking from PSEG-identified leaks on the A and C SW strainers streamed down along SW discharge piping and underneath SW piping insulation potentially masking SW pipe leaks in the A and C SW bays. (NOTF 20167309)

In general, operators initiated NOTFs for deficient conditions annotated in their logs.

However, the team identified two circumstances involving an unsatisfactory jet pump ST and a loose parts monitor alarm in which operators did not initially document the adverse condition in a NOTF. In response to the teams questions, operators initiated NOTFs 20167518 and 20167621 for these issues. During an auxiliary building walkdown, the team identified that three EMIS tags out of a sample of six EMIS tags, should have been removed following corrective maintenance (NOTF 20167321). EMIS tags left hanging after work completion potentially mask the degraded condition should it recur. Based in part on the teams feedback, operations initiated a broad-based EMIS

tag audit and review. Preliminarily, with 433 of 731 open EMIS tasks audited, operations identified an additional 90 EMIS tags that should have been removed, 71 missing EMIS tags, and several other EMIS tag system deficiencies (70034533).

The team independently evaluated the problem identification deficiencies noted above for potential significance. The team determined that none of the individual issues were findings of more than minor significance based upon the guidance in Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues. However, these NRC identified issues represented weak PSEG problem identification.

Audits and self-assessments identified adverse conditions and negative trends, and were generally self-critical and consistent with the teams findings.

b. Prioritization and Evaluation of Issues (1) Inspection Scope The team reviewed the NOTFs listed in Attachment 1 to determine whether PSEG adequately evaluated and prioritized problems. The review included the appropriateness of the assigned significance, the timeliness of resolutions, and the scope and depth of the root cause analyses. The NOTFs reviewed encompassed the full range of PSEG evaluations, including root and apparent cause evaluations. The team selected the NOTFs to cover the seven cornerstones of safety identified in the NRC ROP. A portion of the items chosen for review were those that were age dependent, and accordingly, the scope of review was expanded to five years. In this area, the team reviewed items associated with 1) silting challenges on the SW system and 2) flow-accelerated corrosion issues. The team also considered risk insights from PSEGs PRA to help focus the NOTF sample to the RCIC, RHR, and 1E 250 Vdc systems. Additionally, the team attended the daily management meeting to observe the review process and to understand the basis for assigned significance levels (i.e., SL 1, 2, or 3).

The team also selected a sample of NOTFs associated with previous NRC NCVs and findings to determine whether PSEG evaluated and resolved problems associated with compliance to applicable regulatory requirements and standards. The team reviewed PSEGs assessment of equipment operability, reportability requirements, and extent of condition. The team reviewed PSEGs evaluation of industry operating experience (OE)

information for applicability to their facility. The team also reviewed PSEGs response to NRC identified issues during the inspection.

(2) Observations and Findings The team determined that, in general, PSEG adequately prioritized and evaluated the issues and concerns entered into the corrective action program. Personnel were generally effective at classifying and performing operability evaluations and reportability determinations for discrepant conditions. However, the team noted several weaknesses in PSEGs prioritization and evaluation of degraded conditions. There was one Green finding identified during this inspection involving poor prioritization and evaluation of an EHC oil leak.

In addition, the team identified that PSEG operations and engineering personnel failed to appropriately prioritize and evaluate an adverse condition associated with the C reactor feedwater pump (RFP). Specifically, PSEG failed to properly prioritize and evaluate a C RFP vibration alarm in a timely manner which resulted in continued operation noncompliant with the alarm response requirements of procedure HC.OP-AR.ZZ-0007 for 17 days. The team reviewed IMC 0612, Appendix E, Examples of Minor Issues, and determined that this corrective action performance deficiency was of minor significance and not subject to formal enforcement action.

The team noted that the classification of NOTFs was not always consistent with the corrective action program guidelines. For example, out of a sampling of 105 NOTFs that PSEG categorized as SL X; 49 NOTFs were not appropriately categorized. Some were initially classified as SL-X but met the criteria of a higher SL, while others were initially classified as having a higher SL, but were then inappropriately downgraded.

PSEG initiated NOTF 20167240 to evaluate this condition. The team did not identify any findings of significance involving the 49 individual issues, however, improper classification can affect the adequacy of planned corrective actions.

.1 Electro-Hydraulic Control Oil Leak Results in Manual Scram Introduction. PSEG failed to promptly evaluate and initiate corrective actions for deficiencies associated with the No. 4 CIV actuator resulting in an operational transient (manual reactor scram). The team determined that this self-revealing performance deficiency was of very low safety significance (Green).

Description. On October 4, 2003, control room operators manually scrammed the reactor in accordance with abnormal procedure HC.OP-AB.BOP-0003, Turbine Hydraulic Pressure, due to a severe EHC oil leak. Following the reactor scram, PSEG identified that the oil leak was associated with the No. 4 CIV actuator. PSEG successfully isolated the leak and performed oil additions to maintain the EHC system in service which allowed the turbine bypass valves to control reactor pressure and maintain the normal heat sink during the plant shutdown.

PSEG performed a root cause investigation (order 70033836) to determine the causal factors that contributed to this event. The investigation discovered that PSEG had several opportunities to identify and correct a degraded condition associated with the No. 4 CIV actuator. Specifically, PSEG identified multiple performance deficiencies that contributed to this event including: inadequate maintenance and post-maintenance testing, and improper analysis and evaluation of degraded system performance.

Subsequent to the plant trip, PSEG repaired the No. 4 CIV and performed additional checks to ensure the reliability of the EHC system.

Analysis. The performance deficiencies associated with this event included inadequate problem identification, prioritization, and resolution. The team determined that this finding was of more than minor significance because the failure to identify and correct the No. 4 CIV actuator problem resulted in a manual reactor scram. The team reviewed this finding using the Phase 1 SDP worksheet for initiating events and determined that the issue was of very low safety significance (Green). While the finding resulted in an actual reactor scram, the team determined that the finding did not contribute to a

primary or secondary system loss of coolant accident initiator, did not contribute to a loss of mitigation equipment functions, and did not increase the likelihood of a fire or internal/external flood.

Enforcement. This finding did not represent a violation of NRC regulatory requirements.

Although the Initiating Events cornerstone was affected, the performance deficiencies occurred on a nonsafety-related system. PSEG entered this issue into its corrective action program (NOTF 20161075). (FIN 05000354/2003007-01)

c. Effectiveness of Corrective Actions (1) Inspection Scope The team reviewed PSEGs corrective actions associated with selected NOTFs from Attachment 1 to determine whether the actions addressed the identified causes of the problems. The team reviewed PSEGs timeliness in implementing corrective actions and their effectiveness in preventing recurrence of significant conditions adverse to quality. The team also reviewed NOTFs associated with the NCVs and findings issued since the last PI&R inspection, 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.

(2) Observations and Findings There were two Green findings identified during this inspection that involved untimely resolution of RHR minimum flow valve issues and inadequate follow through of a control room chiller deficiency. In addition, the team noted some weaknesses in PSEGs resolution of degraded conditions, documentation of actions, and completion of identified corrective actions. Examples included:

C PSEG closed out three corrective actions associated with a near violation of fuel reliability limits (SL 1 NOTF 20077752) without completing the identified actions.

In addition, PSEG closed out the overall corrective action order (70019982)

without properly confirming completion of these actions. (NOTF 20167372)

C PSEG did not effectively document and track corrective actions associated with elevated drywell temperatures (70023178, 70031815, 60037493). In addition, engineering did not establish a tracking mechanism to monitor a critical temperature used in their environment qualification calculation for safety-related cable 1GSTE-4967B3. Engineering determined that the cable would remain operable until RF12 with a maximum drywell temperature of 236oF (H-1-GXX-EDC-0112, Rev 2). Since April 2003 (RF11), temperatures in the area of concern were 230 - 235oF. (NOTF 20169764)

C In 2002, the originally installed RCIC jockey pump discharge pressure gauge was indicating low, to the point where the pump failed its inservice test (IST), due to blockage somewhere in the instrument line. For corrective actions, PSEG

installed temporary instrumentation to get an accurate pressure reading and planned to take action to inspect several sections of piping to clear the blockage.

PSEG closed out the associated NOTFs before inspecting all sections of piping.

The RCIC jockey pump passed recent ISTs, but PSEG did not address the reason why the pump had failed (faulty instrumentation readings) and there was no mechanism in place to correct the condition to return the originally installed instrumentation to service. (NOTF 20167574)

C PSEG had not effectively resolved several longstanding equipment deficiencies that potentially caused unnecessary operator burdens such as battery fans tripping, primary containment instrument gas system traps blowing out, B spent fuel pool (SFP) cooling pump trips, a SFP cooling pump oil leak, increased frequency of A/B safety auxiliaries cooling system (SACS) sluicing operations, SW lube water head tank increased makeup, boiler reliability, and recirculation pump vibration.

The team independently evaluated the corrective action program deficiencies noted above for potential significance. The team determined that none of the individual issues were findings of more than minor significance based upon the guidance in IMC 0612, Appendix E, Examples of Minor Issues. However, these issues represented examples where the corrective actions for identified conditions were not effective.

The team noted four examples documented in NRC inspection reports in 2002 where the recurrence of adverse conditions highlighted corrective action effectiveness problems. Additionally, Section 4OA7 of this report documents a PSEG identified issue involving recurrence of a condition adverse to quality due to ineffective corrective actions. However, the team did not identify any documented NRC identified or self-revealing findings in 2003 resulting from inadequate actions for a previous issue.

.1 Residual Heat Removal System Minimum Flow Valve Cycling Introduction. A Green NCV was identified for the failure to implement appropriate corrective actions for conditions adverse to quality on the RHR system as required by 10CFR50, Appendix B, Criterion XVI, Corrective Action.

Description. During a review of NOTFs and system health reports generated for the RHR system between January 2000 and November 2003, the team identified over 18 documented cases where the RHR minimum flow valves (H1BC-HVF007A/B/C/D) did not operate as designed. During each of these cases, the RHR pumps minimum flow valve immediately cycled to the full closed position, then reopened until adequate system flow (>1250 gpm) caused the valve to close as designed. These normally open minimum flow valves are designed to remain open until pump discharge flow exceeds 1250 gpm in order to provide adequate pump cooling during low flow conditions.

PSEG evaluated this condition in November 2000, November 2001, and March 2003 under evaluations 70012187, 70020221, and 70030403 respectively. The evaluations attributed the sporadic premature closing of the valve to the minimum flow valve transmitter sensing a spurious signal (pressure perturbation) on a pump start.

Engineering believed that the pressure from the discharge of the pump on a start was

large enough to create a differential pressure that was momentarily large enough to make the flow transmitter sense a flow above 1250 gpm. Engineering presented a solution to the PSEG Engineering Reliability Committee (i.e., PSEG management) in July 2001; however, planned actions to address this problem have not been implemented.

Additionally, PSEG documented numerous erroneous actuations/alarms of the RHR minimum flow valve Rosemount trip units (H1BC-1BCFISH-N252A/B/C/D-E11) during RHR pump starts. An apparent cause (order 70028671) performed by engineering in October 2003 attributed the erroneous trip unit actuations to the same cause as the minimum flow valve closing during pump starts. However, the team noted several occasions when the spurious actuations of the trip unit occurred when its associated train was not in operation. Specifically, the team noted the following occasions when there was no cause for a pressure perturbation to occur in the system:

C NOTF 20125664 documented on December 20, 2002, that a trip unit actuation occurred on the D RHR train while the pump was not in operation. During this event the D RHR minimum flow valve was observed by operators to be stroking closed. An EO investigated the situation and observed that the trip unit for the minimum flow valve was indicating Gross Fail. The trip unit was reset, all alarms cleared, and operators re-opened the minimum flow valve.

C NOTF 20154885 documented that the B minimum flow trip unit actuated when operators placed a SACS pump in service and the associated RHR train was not in operation on August 7, November 19, and November 27, 2003.

C NOTF 20169284 documented that on December 4, 2003, the B RHR minimum flow valve trip unit actuated when operators placed a SACS pump in service and the associated RHR train was not in operation.

The team investigated the erroneous actuations of the Rosemount trip units and identified OE information that applied to the Hope Creek Rosemount trip units.

Specifically, the team reviewed General Electric (GE) Services Information Letter (SIL)

520, dated August 10, 1990. The SIL describes potential transistor degradation in Rosemount 510DU trip units manufactured prior to December 31, 1980. The SIL recommended that owners of Rosemount model 510DU trip units determine the date code that appears on the transistor in the trip units and either replace the trip unit with a different model or replace the transistor using a replacement kit provided by Rosemount Inc.

The team reviewed PSEGs response to GE SIL 520 (OEPRVW 00317) to determine if the erroneous actuations of the trip units described above were associated with the information contained in the GE SIL. The team identified that PSEG did not perform the recommended trip unit inspection and replacement of potentially defective transistors.

Instead, PSEG initially checked for the transistor defect by measuring the voltage on the output relays for both the normally energized and normally de-energized trip units. The team questioned the adequacy of PSEGs initial response and corrective actions due to the potential system responses that could occur from failed trip unit (i.e., system not actuating when called upon or spurious actuations when not desired). PSEG initiated

NOTF 20170271 to re-evaluate the adequacy of their response to GE SIL 520 and the corrective actions they had implemented. PSEG does not believe that the spurious trip unit actuations were related to the problems discussed in GE SIL 520; however, they initiated NOTF 20170190 to further investigate and correct the issue.

Analysis. The performance deficiency associated with this finding was a failure to initiate timely corrective actions to ensure the RHR system would remain unaffected by undesired cycling of its associated minimum flow valve during pump starts and erroneous trip unit signals. The team determined that this finding was more than minor because it affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. The team reviewed this finding using the Phase 1 SDP worksheet for Mitigating Systems and determined that the finding was of very low safety significance (Green), since the performance deficiency had not resulted in any loss of the RHR safety system function.

Enforcement. Title 10 to CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, since January 2000 PSEG failed to correct deficiencies associated with the RHR minimum flow valve and associated trip units in a timely manner to ensure that the RHR system would remain reliable and available when needed. Because the failure to correct this condition adverse to quality is of very low significance and has been entered into the corrective action program (NOTFs 20169830 and 20170190), this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy, issued May 1, 2000 (65FR25368). (NCV 05000354/2003007-02)

.2 Inadequate Corrective Actions on the B Control Area Room Chiller Introduction. A Green self-revealing NCV was identified for the failure to correct a B control room chiller problem as required by 10CFR50, Appendix B, Criterion XVI, Corrective Action.

Description. On September 9, 2003, the B control area chiller experienced surging when operators placed it in service. A PSEG chiller walkdown identified elevated condenser pressure. Engineering initiated NOTF 20158321 to investigate the elevated condenser pressure in the chiller. Engineering recommended a condenser purge to check for non-condensible gasses and an inspection of the condenser float valves based on an evaluation of chiller performance following the purge activities.

Maintenance completed the purge activities on September 12 and closed the work order (60039114) associated with the chiller troubleshooting. Engineering and maintenance performed an evaluation of the chillers performance on September 15 and concluded that additional troubleshooting was needed to determine the cause for the elevated condenser pressure. On October 2, operators declared the B control room chiller inoperable after it tripped when they attempted to place it in service. Maintenance performed an investigation and attributed the trip to separation of the high side float

valve assembly ball-arm from the valve shaft due to improper tensioning of the clamp bolt.

PSEGs apparent cause evaluations (70033834 and 70033930) identified that the work order used to perform the purge activities was closed after completion of the job. The team noted that the recommended condenser float valve inspection activity had not been performed and determined that this allowed the float valve assembly problem to remain undetected until the chiller trip on October 2.

Analysis. The performance deficiency associated with this finding was failure to perform adequate corrective actions to ensure the availability and reliability of the B control area chiller. The team determined that this finding was of greater than minor significance since the performance deficiency affected the Mitigating System cornerstone objective to ensure the availability and reliability of mitigating systems such as the B control area chiller. The team reviewed this finding using the Phase 1 SDP worksheet for Mitigating Systems and determined that the B chiller was potentially inoperable for a period of up to 13 days which exceeded the TS allowed outage time of 7 days. This required that a Phase 2 SDP analysis be performed.

The team determined that a Phase 2 analysis was not applicable since the control area chillers were not modeled as a mitigating system in the Phase 2 worksheets. As a result, the Regional Senior Reactor Analyst (SRA) performed a Phase 3 analysis of the issue and concluded that it was of very low significance (Green). Because the control area chillers were not modeled within the NRCs Standardized Plant Analysis Risk (SPAR) Model for Hope Creek, the SRA determined the change in CDF using the risk achievement worth (RAW) obtained from PSEGs PRA. The SRA concluded that the RAW for the control area chiller of 1.0 was reasonable and the resultant increase in CDF was negligible. Therefore, the issue was determined to be of very low significance (Green).

Enforcement. Title 10 to CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, from September 9 to October 2, 2003, PSEG failed to correct deficiencies associated with the B control room area chiller in a timely manner to maintain the chiller reliable and available when needed. Because the failure to correct this condition adverse to quality is of very low significance and has been entered into the corrective action program (NOTFs 20161194 and 20160842), this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy, issued May 1, 2000 (65FR25368). (NCV 05000354/2003007-03)

4OA6 Meetings, including Exit The team presented the inspection results to Mr. John Carlin, Mr. Dave Garchow, Mr.

Jim Hutton and other members of PSEG management on December 12, 2003. PSEG management stated that none of the information reviewed by the inspectors was considered proprietary.

4OA7 Licensee-Identified Violations The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a NCV.

C 10 CFR 50, Appendix B Criterion XVI, Corrective Action, requires that conditions adverse to quality are promptly identified and corrected. Contrary to this, on September 15, 2003, PSEG identified that they had failed to complete weekly ST task HC461121 for the average power range monitor (APRM) flow unit summers as required by TS 4.3.1.1 and TS 4.3.6. In addition, PSEG identified that they had missed this same ST on two previous occasions in 2003 (70029503 and 70029791). PSEG entered this issue into their problem corrective action system as NOTF 20158772. This finding is of very low safety significance because there was not an actual loss of safety function. Operators satisfactorily completed the APRM flow unit ST and determined that the flow units would have performed their intended trip function.

A-1 ATTACHMENT SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel S. Afarian, System Engineer J. Anthes, System Engineer D. Bartlett, System Engineer K. Berger, Licensing Engineer N. Bergh, Quality Assurance Manager M. Bergman, System Engineer H. Berrick, Senior Licensing Engineer, Nuclear Licensing D. Boyle, Acting Operations Manager R. Henriksen, Corrective Action Program Manager J. Hutton, Hope Creek Plant Manager M. Ivanick, Security Operations Superintendent P. Koppel, Principal Nuclear Engineer T. Lake, Employee Concerns J. Morrison, Engineering Supervisor M. Morroni, Supervisor Minor Modifications and Temporary Modifications M. Murray, Staff Engineer, Flow-Accelerated Corrosion Program M. Pfizenmaier, Engineering Supervisor, System Engineering M. Quadir, Electrical Engineer J. Rodriguez, Lube Oil Program Manager B. Sebastian, Technical Superintendent, HC Radiation Protection J. Stavely, Reactor Engineering Supervisor T. Straub, Security Manager P. Tocci, Maintenance Manager B. Tyers, System Engineer L. Wagner, Plant Support Manager LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened/Closed 05000354/2003007-01 FIN PSEG failed to promptly evaluate and correct deficiencies associated with the No.

4 CIV actuator resulting in an operational transient (manual reactor scram). (Section 4OA2.b.2.1)

A-2 05000354/2003007-02 NCV PSEG failed to promptly take actions to address conditions adverse to quality concerning RHR minimum flow valve undesired cycling during RHR pump starts and erroneous RHR trip unit signals.

(Section 4OA2.c.2.1)05000354/2003007-03 NCV PSEG failed to adequately implement identified corrective actions for a B control area chiller deficiency resulting in a chiller trip when it was placed in service. (Section 4OA2.c.2.2)

LIST OF DOCUMENTS REVIEWED Audits and Self-Assessments Quality Assessment/Onsite Independent Review Quarterly Report; dated 10/29/03, 7/29/03, and 5/8/03 QA Self-Assessment Report 2003-0176, dated 7/11/03 Corrective Action Effectiveness Root Cause Corrective Action Status and Effectiveness (70027584), updated 11/17/03 Implementation and Use of Corrective Action Trend Program (CAP) Focused Self-Assessment, dated 10/30/03 Hope Creek Problem Identification and Resolution (PIR) Assessment, dated 11/14/03 Review of Operator Training and Plant Human Performance Events (80054179 - 0320), dated 6/6/03 Effectiveness of Corrective Actions (Operations Training) (80035760 0020), dated 4/12/02 Training Department Corrective Action Response Evaluation (80035760-250), dated 8/25/02 Corrective Action Program 2002 - 2003 Business Plan Biennial Assessment, dated 5/29/02 Operating Experience 2002-2003 Business Plan Biennial Assessment, dated 5/29/02 Implementation and Use of Operating Experience (OE) Focused Self-Assessment, dated 9/30/01 Performance and Protection Self-Assessment; dated 6/18/01, 11/26/01, 5/9/02 Annual Evaluation of PADS Data Validation Results, dated 12/19/01 Annual Evaluation of PADS Data Validation Results - 2002, dated 1/3/03 Corrective Action Program Effectiveness Emergency Services Level 1 & 2 Notifications March 2001 to January 2003 (80056411)

June 2003 Hope Creek Operations Observation Card Profile 6/1/03 to 6/30/03 July 2003 Hope Creek Operations Observation Card Profile 7/1/03 to 7/30/03 August 2003 Hope Creek Operations Observation Card Profile 8/1/03 to 8/31/03 September 2003 Hope Creek Operations Observation Card Profile 9/1/03 to 9/30/03 October 2003 Hope Creek Operations Observation Card Profile 10/1/03 to 10/31/03 Hope Creek Shift Relief/Turnover and Annunciator Response Standards (80031644), dated 1/2/02 Hope Creek Operations SSC Operability Screenings (80034192), dated 6/4/02 Attachment

A-3 Hope Creek Component Configuration Control (80043424), dated 6/18/02 Hope Creek Operations Procedure Use and Adherence (80039281), dated 12/9/02 Salem/Hope Creek Operator Rounds (80057365), dated 7/25/03 QA Assessment Report 2003-0227, Solid Radioactive Waste Packaging and Transportation, dated 9/26/03 QA Assessment Report 2003-2040, Surveys and Monitoring, dated 3/22/02 Self-Assessment Report 80043789, Focused Self-Assessment of Radiation Protection Practices, dated 6/28/03 Self-Assessment Report 80054140, Ongoing Self-Assessment of Radiation Protection Corrective Actions, dated 3/3/03 Self-Assessment Report 80058348, Radiation Protection Assessment of Corrective Actions, dated 3/31/03 S/A Report 80053229, Engineering Implementation of the Performance Improvement Process to Address Equipment Failures, Attachments A & B, dated 12/5/02 S/A Report 20063853, Effectiveness of Trending in the Technical Support and Nuclear Reliability Organization, dated 6/28/01 Reliability Programs Assessment on Corrective Action Trends, dated 2/14/02 QA Assessment Report 2002-0016, Emergency Preparedness (EP), dated 3/5/02 Corrective Action Program Status Hope Creek Maintenance Department, dated 11/10/03 QA Assessment Report 2003-0216 - Preventive Maintenance Program, dated 10/1/03 QA Assessment Report 2002-0149 - Maintenance Corrective Actions and Self Assessments, dated 6/26/02 QA Assessment Report 2003-0040 - Work Package Quality, dated 3/25/03 QA Assessment Report 2003-0243 - Maintenance Activities, dated 9/16/03 Calculations HC Class IE 250 V DC Station Battery & Charger Sizing Calculation (E-5.1), Rev. 7 Evaluation of Structure Integrity of As-built 125V Battery Rack Assembly (678-97), Rev. 3 Completed Surveillances RCIC Piping and Flow Path Verification - Monthly (HC.OP-ST.BD-0001), dated 10/26/03 RCIC Functional Verification - 18 Months (HC.OP-ST.BD-0003), dated 5/5/03 Reactor Core Isolation Cooling Jockey Pump - BP228 - Inservice Test (HC.OP-IS.BD-0002),

dated 8/23/02 Reactor Core Isolation Cooling Pump-OP203 - Inservice Test (HC.OP-IS.BD-0001), dated 10/14/03 and 7/9/2003 Reactor Core Isolation Cooling System Valves - Inservice Test (HC.OP-IS.BD-0101), dated 10/9/03 RCIC System Functional Test (Low Pressure) - 18 Months and RCIC System Response Time Test (High Pressure) (HC.OP-FT.BD-0002), dated 6/16/01 AP202, A Residual Heat Removal Pump In-Service Test (HC.OPIS.BC-0001), dated 10/14/03 BP202, B Residual Heat Removal Pump In-Service Test (HC.OP-IS.BC-0003), dated 9/5/03 CP202, C Residual Heat Removal Pump In-Service Test (HC.OP-IS.BC-0002), dated 4/13/03 and 9/24/03 DP202, D Residual Heat Removal Pump In-Service Test (HC.OP-IS.BC-0004), dated 11/5/03 Attachment

A-4 Residual Heat Removal Subsystem A Valves - Inservice Test (HC.OP-IS.BC-0101), dated 10/16/03 Residual Heat Removal Subsystem B Valves - Inservice Test (HC.OP-IS.BC-0102), dated 9/2/03 Residual Heat Removal Subsystem C Valves - Inservice Test (HC.OP-IS.BC-0103), dated 9/24/03 Residual Heat Removal Subsystem D Valves - Inservice Test (HC.OP-IS.BC-0104), dated 11/3/03 RHR System Piping and Flow Path Verification - Monthly (HC.OP-ST.BC-0001), dated 11/9/03 LPCI Subsystem A ECCS Time Response Functional Test - 18 Months (HC.OP-ST.BC-0004),

dated 11/16/03 LPCI Subsystem B ECCS Time Response Functional Test - 18 Months (HC.OP-ST.BC-0005),

dated 11/23/03 LPCI Subsystem C ECCS Time Response Functional Test - 18 Months (HC.OP-ST.BC-0006),

dated 11/19/03 LPCI Subsystem D ECCS Time Response Functional Test - 18 Months (HC.OP-ST.BC-0007),

dated 4/30/03 G Diesel Fuel Oil Transfer Pump-GP401 - Inservice Test (HC.OP-IS.JE-0007), dated 11/7/03 Emergency Diesel Generator DG400 Operability Test - Monthly (HC.OP-ST.KJ-0004), dated 11/3/03 Emergency Diesel Generator CG400 Operability Test - Monthly (HC.OP-ST.KJ-0003), dated 11/17/03 Emergency Diesel Generator BG400 Operability Test - Monthly (HC.OP-ST.KJ-0002), dated 10/27/03 Emergency Diesel Generator AG400 Operability Test - Monthly (HC.OP-ST.KJ-0001), dated 11/3/03 Main Turbine Functional Test - Weekly (HC.OP-FT.AC-0001), dated 9/29/03 Main Turbine Functional Test - Monthly (HC.OP-FT.AC-0002), dated 8/10/03 Main Turbine Functional Test - Monthly (HC.OP-GT.AC-0002), dated 9/7/03 Turbine Valve Testing - Quarterly (HC.OP-ST.AC-0002), dated 10/2/03 250 Volt Quarterly Battery Surveillance (HC.MD-ST.PJ-0002), dated 7/10/03 and 5/1/03 60 Months Surveillance & Performance Discharge Test of 250 Volt Batteries using BCT-2000- 10D431 (HC.IC-ST.PJ-0001), dated 5/01/03 18 Months Surveillance & Performance Discharge Test of 250 Volt Batteries using BCT-2000 (HC.IC-ST.PJ-0001), dated 10/23/01 Corrective Action Notifications 20013606 20061285 20070798 20076067 20020251 20064478 20070977 20076308 20032300 20064604 20071415 20076331 20045585 20064673 20071724 20077271 20049374 20065618 20073395 20077752 20053924 20067698 20073410 20079321 20058821 20067956 20073757 20079789 20061008 20068730 20074076 20080049 20061125 20069498 20075878 20080357 Attachment

A-5 20080532 20095548 20137653 20160576 20081393 20096896 20138361 20160986 20082039 20096898 20138390 20161067 20082238 20096899 20138898 20161075 20082798 20096912 20141383 20161205 20083950 20097165 20141739 20161345 20084608 20099110 20141884 20161416*

20084806 20099863 20142336 20161519 20085143 20100743 20142501 20161707 20085181 20100961 20142502 20161829 20085376 20101456 20143717 20162042 20085377 20101661 20144309 20162049 20085380 20101666 20144508 20162262 20085401 20101679 20145274 20162879 20086203 20101814 20145275 20163354 20086308 20101826 20145972 20163675 20086586 20101946 20146382 20163764 20087240 20103600 20146383 20164153 20087290 20103992 20146384 20164873 20087802 20104249 20146525 20166286 20088044 20105095 20148450 20166529 20088107 20105944 20148882 20166738*

20088191 20108183 20150075 20166841 20088966 20108660 20151830 20166842 20089420 20109206 20152465 20167105*

20089826 20109266 20152829 20167114*

20090247 20111780 20152830 20167189*

20090358 20112255 20152863 20167190*

20090842 20113480 20154856 20167193*

20090944 20114125 20154885 20167194*

20091056 20114148 20155142 20167226*

20091217 20116473 20155234 20167229*

20091537 20116804 20155712 20167230*

20091651 20120281 20155827 20167240*

20091720 20120658 20156216 20167271*

20091845 20123418 20157243 20167272*

20091906 20123654 20157446 20167273*

20092017 20125664 20157513 20167274*

20092051 20127192 20157660 20167275*

20092148 20127734 20158015 20167309*

20092342 20131043 20158175 20167324*

20093770 20132306 20158218 20167372*

20094138 20133060 20158321 20167377*

20094355 20133344 20158698 20167384*

20094581 20134901 20159590 20167453*

20094731 20136006 20159721 20167454*

20095535 20136635 20159897 20167482*

Attachment

A-6 20167518* 20167768 20169284 20169655*

20167574* 20167769 20169318 20169830*

20167580 20167770 20169541 20169993*

20167601* 20167825 20169600* 20170146*

20167605* 20167855 20169629 20170190*

20167621* 20167867* 20169630 20170271*

20167629* 20168056 20169632 20167641 20168552 20169646*

20167689* 20168870 20169653*

• NRC Identified During Inspection Drawings System Isometric/Reactor Building HPCI Turb. Supply & Exhaust (1-P-FD-01), Rev. 24 System Isometric/Reactor Building RHR Pumps A & C Discharge (1-P-BC-03), Rev. 22 Single Line Meter & Relay Diagram - 250 V DC System-Unit-1 (E-0011-1-15), Sh.1, Rev. 11 Single Line Meter & Relay Diagram - 250 V DC System-Unit-1 (E-0011-1-15), Sh.2, Rev. 13 P&ID Residual Heat Removal (M-51-1), sheet 1 of 2 P&ID Residual Heat Removal (M-51-1), sheet 2 of 2 P&ID Auxiliary Building Diesel Area Air Flow Diagram (M-85-1), sheet 2 of 2 Evaluations 70015100 70022634 70028425 70034210 70015674 70022962 70028671 70034724 70016945 70023106 70028761 80022028 70017424 70023169 70029462 80029521 70017558 70023178 70030270 80038543 70018936 70023206 70030705 80040562 70019007 70023241 70031327 80041711 70019266 70023712 70031815 80041917 70019882 70024748 70032147 80043181 70020961 70025232 70032411 80044290 70020994 70025240 70032987 80047885 70021516 70025544 70033544 80048938 70021559 70025568 70033819 80056544 70021623 70025620 70033834 80061290 70021767 70026656 70033836 80063335 70021822 70027584 70033930 Miscellaneous Security Information Bulletin, dated 11/18/03 Hope Creek Generating Station Turnover Sheet, Tuesday, November 18, 2003 CAS/SAS Turnover Sheet, dated 11/18/03 Attachment

A-7 A Letter From Roy Anderson, President and CNO, to PSEG Nuclear Personnel; dated 11/21/03, 12/5/03, and 12/11/03 Configuration Baseline Document for Reactor Core Isolation Cooling System, Rev. 0 Minor Modifications Database, as of 11/20/03 Design Change Package Database, as of 11/01/03 Control Room Narrative Logs, dated 9/1/03 to 10/30/03 Hope Creek Temporary Modification Summary, dated November 14, 2003 Hope Creek Operations Focus Items, dated November 17, 2003 Non-Cited Violations 50-354/01-09-03 50-354/01-11-03 50-354/02-04-03 50-354/02-06-04 50-354/01-11-01 50-354/02-02-01 50-354/02-05-03 50-354/01-11-02 50-354/02-02-03 50-354/02-06-03 Nuclear Review Board (NRB)

Nuclear Review Board Meeting Minutes, No. 02-04, dated 10/10/02 Nuclear Review Board Meeting Minutes, No. 02-02, dated 3/25/02 Subcommittee Restructuring and NRB Action Item Teleconference, dated 10/13/03 Nuclear Review Board Meeting Minutes, No. 02-01, dated 2/14/02 Nuclear Review Board Meeting Minutes, No. 03-01, Revised, dated 2/28/03 Nuclear Review Board Meeting Minutes, No. 03-02, dated 6/19/03 Nuclear Review Board Meeting Minutes, No. 01-03, dated 8/10/01 Executive Summary - September 2001 NRB, dated 10/9/01 Operating Experience Hydrogen Combustion Events in Foreign BWR Piping (Information Notice 2002-15), dated 4/12/02 Hydrogen Combustion Events in Foreign BWR Piping (Information Notice 2002-15, Supplement 1), dated 5/6/03 Fairbanks Morse Engine Service Information Letter Issue 22, dated 1/15/03 OE Corrective Action Verification Form, Information Notice: 90-28, Potential Error in High Steamline Flow Setpoint Nuclear Department Action Tracking System Response Approval Form, Information Notice: 86-14, Supplement 2, Overspeed Trips of AFW, HPCI, and RCIC Turbines OE15574, RCIC Pump Flow Oscillation Due to Incorrect Gain Setting of the Flow Controller OE15688, Auxiliary Feed Water Pump Terry Turbine over Speed Trip OE15497 (Davis Besse battery explosion)

Licensee Event Report (LER) 94-023-01, Reactor Scram Due to Spurious Signals From Undamped Rosemount Model 1153 Transmitters Information Notice 86-74, Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves Information Notice 87-10, Potential for Water Hammer During Restart of Residual Heat Removal Pumps Attachment

A-8 General Electric Service Information Letter (GE SIL) - 388, RHR Valve Misalignment During Shutdown Cooling Operation for BWRs 3/4/5 and 6 General Electric Service Information Letter (GE SIL) - 520, Transistor Degradation in Rosemount 510DU Trip Units, dated August 10, 1990 Procedures Scheduler/Senior Scheduler Deskguide (SH.WM-DG-0001), Rev. 1 Procurement and Control of Materials and Services (NC.PM-AP.ZZ-0019), Rev. 0 Self-Assessment Process (NC.QA-AP.ZZ-0077), Rev. 0 Operating Experience (OE) Program (NC.QA-AP.ZZ-0054), Rev. 1 Operability Assessment and Equipment Control Program (SH.OP-AP.ZZ-0108), Rev. 11 Notification Process (NC.WM-AP.ZZ-0000), Rev. 6 Diesel Generator Technical Specification Surveillance and P.M., Attachment 1 (HC.MD-ST.KJ-0001), Rev. 31 Self-Assessment Process (NC.QA-AP.ZZ-0077), Rev. 0 Low Voltage Type AKR Breaker Air Circuit Breaker Inspection and Preventive Maintenance (HC.MD-ST.ZZ-006), Rev. 15)

Operations Standards (SH.OP-AS.ZZ-0001)

Conduct of Infrequently Performed Tests or Evolutions (SH.OP-AP.ZZ-0084)

Reactivity Plan Desk Top Guide (HC.RE-DG.ZZ-0001)

Decay Heat Removal Operation (HC.OP-SO.BC-0002)

Residual Heat Removal System Operation (HC.OP-SO.BC-0001)

Abnormal Operating Procedure - Loss of HVAC (HC.OP-AB.ZZ-0154)

HVAC (HC.OP-AB.HVAC-0001)

RHR - Division 4 Channel E11-N652D Pump Discharge Flow (HC.IC-FT.BC-0008)

Combination Intercept Valves (CIV) Overhaul (HC.MD-CM.AC-0003)

Control Area Ventilation System Operation (HC.OP-SO.GK-0001)

System Health Reports and Trending Data System Health Report, Hope Creek Generating Station HPCI and RCIC Batteries - 10-D421, 10-D-431 3rd Quarter of 2003 System Health Report, Hope Creek Residual Heat Removal (RHR) - BC, Period 6/1/03 to 8/31/03, Period 3/1/03 to 5/31/03, Period 1/1/03 to 2/28/03, Period 10/01/02 to 12/31/02 Hope Creek Reactor Core Isolation Cooling System (BD/FC) Period 6/1/03 to 8/31/03, Period 3/1/03 to 5/31/03, Period 10/31/02 to 2/28/03, Period 8/1/02 to 10/31/02 System Health Report, Service Water (EA) and Traveling Screen and Screen Wash (EP), 2nd and 3rd Quarters of 2003 Component Health Report, Circuit Breakers, period 7/1/03 to 9/30/03 PIRS Summation, Top Ten Systems, dated 11/17/03 System Performance Monitoring Notebook - Reactor Core Isolation Cooling System Residual Heat Removal System Engineering Notebook A RHR Pump Upper Bearing Oil Analysis Report, dated 9/29/03 A RHR Pump Upper Bearing Oil Analysis Report, dated 8/14/03 C RHR Pump Upper Bearing Oil Analysis Report, dated 7/29/03 D RHR Pump Upper Bearing Oil Analysis Report, dated 8/25/03 Attachment

A-9 Vendor Information General Electric Instruction Manual For Vendor Supplied Instruments - Volume II GEY 5650 (PN1-H21-S001-0228)

General Electric Vendor Manual - Turbine - EHC Section (GEK 63334)

Work Orders 60013405 60027784 60037416 60040787 60015966 60027785 60037493 60032212 60019809 60029411 60038519 Attachment

A-10 LIST OF ACRONYMS USED APRM Average Power Range Monitor CAS Central Alarm Station CDF Core Damage Frequency CFR Code of Federal Regulations CIV Combined Intermediate Valve ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EHC Electro-Hydraulic Control EMIS Equipment Malfunction Information System EO Equipment Operator GE General Electric GPM Gallons Per Minute HCGS Hope Creek Generating Station HPCI High Pressure Coolant Injection IMC Inspection Manual Chapter IPE Individual Plant Examination IST Inservice Test NCV Non-Cited Violation NOTF Notification (PSEG input into their corrective action program)

NRB Nuclear Review Board NRC Nuclear Regulatory Commission OE Operating Experience PARS Publicly Available Records PI&R Problem Identification and Resolution PRA Probabilistic Risk Assessment PSEG Public Service Electric Gas Nuclear, LLC QA Quality Assessment RAW Risk Achievement Worth RCIC Reactor Core Isolation Cooling RF Refueling Outage RFP Reactor Feedwater Pump RHR Residual Heat Removal ROP Reactor Oversight Process SACS Safety Auxiliaries Cooling System SAS Secondary Alarm Station SDP Significant Determination Process SFP Spent Fuel Pool SIL Services Information Letter SL Significance Level SPAR Standardized Plant Analysis Risk SRA Senior Reactor Analyst ST Surveillance Test SW Service Water TS Technical Specification Attachment