IR 05000272/1999005

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Insp Repts 50-272/99-05 & 50-311/99-05 on 990530-0711.No Violations Noted.Major Areas Inspected:Licensee Performance Indicators
ML18107A479
Person / Time
Site: Salem  PSEG icon.png
Issue date: 08/10/1999
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18107A478 List:
References
50-272-99-05, 50-311-99-05, NUDOCS 9908170039
Download: ML18107A479 (31)
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Docket Nos:

License Nos:

,Report No:

Licensee:

Facility:

Location:

Dates:

Inspectors:

Approved By:

9908170039 990810 PDR ADOCK 05000272 G

PDR U.S. NUCLEAR REGULATORY COMMISSION 50-272, 50-311 DPR-70, DPR-75

REGION I

50-272/99-05, 50-311/99-05 PSEG Nuclear LL Salem Nuclear Generating Station, Units 1 & 2 P.O. Box 236 Hancocks Bridge, NJ 08038 May 30- July 11, 1999 Scott A. Morris, Senior Resident Inspector F. Jeff Laughlin, Resipent Inspector Ho K. Ni~h, Resident Inspector Glenn W. Meyer, Chief, Projects Branch 3 Division of Reactor Projects

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SUMMARY OF FINDINGS Salem Generating Station, Units 1 & 2 NRC Inspection Report 50-272 & 311/99-05 The report covers a 6-week period of resident inspection using the guidance contained in NRC Inspection Manual Chapter 2515*.

Inspection findings were assessed according to potential risk significance and were assigned colors of green, white, yellow, or red. The inspection found only green findings, which were indicative of issues that, while not necessarily desirable, represented little risk to safety. White findings would have indicated issues with some increased risk to safety and which may have required additional NRC inspections. Yellow findings would have indicated more serious issues with higher potential risk to safe performance and would have required the NRC to take additional actions. Red findings would have represented an unacceptable loss of margin to safety and would have resulted in the NRC taking significant actions that could have included ordering the plant to shut down. The findings, considered in total with other inspection findings and performance indicators, will be used to determine overall plant performanc Cornerstone: Initiating Events

Green. PSEG maintained appropriate control of combustible material and ignition sources in inspected areas. In general, impaired fire barriers were clearly tagged and documented in the corrective action program (CAP). However, the inspectors discovered some minor deficiencies such as a fire door which would not completely close without operator assistance. (Section 1 ROS)

Cornerstone: Mitigating Systems

Green. PSEG Nuclear personnel properly monitored CFCU performance for reliability and unavailability. However, while PSEG's recent change in the CFCU train unavailability performance criteria was acceptable, it was not based on an evaluation of all of the appropriate factors. Also, the goals for the diesel generators were weak in that the cause of the associated unavailability was not addressed. (Section 1 R12)

Green. PSEG Nuclear operators appropriately assessed three degraded equipment conditions in terms of their impact on the design basis functions of the affected system Each of the operability evaluations were completed in a timely manner. However, some of the associated compensatory measures were either incomplete or poorly controlle (Section 1R15)

Performance Indicator Verification

PSEG Nuclear personnel established and implemented adequate procedures to produce the performance indicators for Reactor Coolant System Leakage, Reactor Coolant System Specific Activity, and Containment Leakage. Leakage and activity ii

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Other measurements, and the reported data for these indicators were accurate and met Pl reporting guidance. (Section 40A3)

The inspectors concluded that PSEG had previously implemented appropriate actions for the white Pl at each unit in Protected Area Security Equipment Performance Index when the applicable events occurred in 1998. No additional NRC inspection is warranted or planned. (Section 40A4)

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  • TABLE OF CONTENTS REACTOR SAFETY.......................................................... 1 1 R05 Fire Protection................................................... 1 1 R12 Maintenance Rule Implementation................................... 1 1R15 Operability Evaluations............................................ 3 1R16 Operator Workarounds............................................ 4 OTHER ACTIVITIES.......................................................... 5 40A2 Performance Indicator Verification................................... 5 40A3 Event Follow-up.................................................. 5 (Closed) LER 50-311/99-002-00 and -01........................ 5 (Closed) LER 50-272/99-003-00............................... 6 (Closed) LER 50-272/99-004.................................. 6 (Closed) LER 50-272/99-005-00................................ 6 (Closed) LER 50-311/99-006-00 and -01........................ 6 40A4 Other.......................................................... 6 Senior Management Reorganization..........,................. 6 40A5 Management Meetings............................. '............... 7 Exit Meeting Summary............. ~......................... 7 Predecisional Enforcement Conference Summary................. 7 PSEG Nuclear/NRG Management Meeting...................... 7

ITEMS OPENED AND CLOSED................................................. 8 LIST OF BASELINE INSPECTIONS PERFORMED................................... 9 LIST OF ACRONYMS USED.................................................. 10

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Report Details Summary of plant status Unit 1 began the period at full power. On June 2, 1999, operators completed an unplanned load *

reduction to 78% in order to repair a failed valve on a turbine auxiliaries cooling system heat exchanger. Full power was restored on June 7, 1999. The unit remained at full power throughout the remainder of the perio Unit 2 began the period at 45% power in the midst of recovering from the tenth refueling outag Full power was achieved on June 6, 1999. Operators conducted a planned load reduction to 85% on June 23, 1999, in order to repair a feedwater heater steam leak. Full power was restored on June 25, 1999, where it remained for the balance of the perio REACTOR SAFETY (Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity)

1 ROS Fire Protection Inspection Scope (71111-5)

The inspectors toured selected high fire risk plant areas, including the relay rooms, diesel generator rooms and key safety equipment on the 84 foot level of the auxiliary building. They assessed PSEG Nuclear's control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measure Observations and Findings Overall, the inspectors noted appropriate control of combustible material and ignition sources in inspected areas. In general, impaired fire barriers were clearly tagged and documented in the corrective action program (CAP). However, the inspectors discovered some minor deficiencies such as a fire door which would not.completely.

close without operator assistance, and a small bucket which collected oil from a charging pump oil leak. Once informed, PSEG Nuclear personnel either corrected the deficiencies or entered in them in the CAP. The inspector determined that for the fire door, the violation represented a minor violation which is not subject to formal enforcement actio R12 Maintenance Rule Implementation Inspection Scope (71111-12)

The inspectors assessed maintenance rule (M-rule) implementation for the 11 containment fan cooler unit (CFCU) following a series of associated service water (SW)

leaks. (The CFCU and the SW systems are interrelated in that SW provides cooling water to the CFCU heat exchangers.) The noted leaks indirectly resulted in a May 1999 automatic reactor trip at Unit 1 (see NRC Inspection Report 50-272&311/99-04). The l

  • inspectors also reviewed the basis for a recent increase in the CFCU train unavailability performance threshol Additionally, the inspectors reviewed M-rule implementation for the emergency diesel generators (EDG) and the gas turbine generator (GTG), both of which were category a(1) systems per the rule. The inspectors noted that the Salem Individual Plant Examination (a quantitative risk assessment) characterized both of these system's as risk significant mitigating system Observations and Findings CFC Us The basis for a recent change in CFCU train unavailability performance criteria was acceptable, but had not considered all appropriate factors. In December 1998 an M-rule expert panel approved an increase in the criteria for CFCU train unavailability from 325 to 650 hours0.00752 days <br />0.181 hours <br />0.00107 weeks <br />2.47325e-4 months <br /> per plant operating cycle to account for recent SW system reliability problems. The expert panel approved the change because a quantitative risk asses~ment indicated that core damage frequency (CDF) increased only slightly with the increase in CFCU unavailability. However, the inspectors noted that this analysis did not consider the impact on large early release frequency (LERF), which is an analytical risk result that measures the likelihood of containment failure. The inspectors judged that an assessment of the increase in LERF would have been more appropriate since the.

CFCUs directly impact containment performance. PSEG personnel subsequently performed a LERF evaluation using the new unavailability criteria and determined that the increase in LERF was minimal (i.e., approximately 1.7 E-7 per reactor year).

Personnel monitored.CFCU performance at the train level and appropriately tracked reliability and unavailability. Additionally, PSEG Nuclear properly accounted for the accumulation of 11 CFCU unavailability time during the associated leak repair effort Based on predefined SW and CFCU system boundaries, PSEG Nuclear considered the CFCU leaks to be a functional failure of the SW system rather than of the CFCU itsel The Inspectors concluded that this approach was reasonabl EDGs and GTG Both the EOG and GTG systems were in a goal monitoring status per M-rule section a(1)

since the systems had previously exceeded the unavailability performance criteri However, the established goals were simply that future system unavailability not exceed the originally established performance criteria over the next operating cycle. The

. inspectors concluded that while this approach was acceptable, the performance goals were weak in that they had not addressed the specific issues that caused the performance criteria to be exceeded in the first place. The inspectors noted that monitoring data indicated that both systems were trending toward goal achievement and a return to M-rule a(2) status. PSEG Nuclear acknowledged the inspectors' conclusio R15 Operability Evaluations Inspection Scope (71111-15)

The inspectors evaluated three of the four active operability evaluations (OE) at the Salem stations, specifically (by title/tracking number):

  • Gross air leakage from 21SW102 control valve actuator (990521189)
  • Service water bay ventilation fan failure to operate in automatic (990630069)

This evaluation included a review of applicable design and licensing basis information, field observations of affected equipment, an assessment of compensatory measures, walkdowns of redundant systems, and a verification that the issues were appropriately entered into the corrective action progra Observations and Findings Operators appropriately assessed each of the noted degraded conditions in terms of their impact on the design basis functions of the affected systems. Each of the OEs were completed in a timely manner, consistent with the guidance in NRC Generic Letter 91-18 (revision 1), "Resolution of Degraded and Non-Conforming Conditions."

Additionally, the operations staff clearly established the basis for system operability in corrective action program documentation. Compensatory measures instituted for the various issues were also clearly defined and had little potential to impact the operators'

ability to respond to plant event Implementation of some of the compensatory measures were incomplete or poorly controlled. For example, the inspectors identified a discrepancy associated with the compensatory actions for the 21SW102 degraded condition in that the valve was not

"failed open" as described in the *oE. T_he inspectors determined that while the valve was in fact open, operators did not employ any means to ensure that it remained in this condition. Another example involved the 11 SW99 back-leakage issue. In this case, the OE specified that a normally open valve upstream of the check valve be shut when service water temperatures reached 80 degrees F. The inspectors verified that this action was completed, but operators did not tag the valve in an off-normal condition per PSEG Nuclear expectations. Additionally, the tagging request information system. was not updated to reflect this change in valve position. Both of these issues were promptly corrected once the inspector informed control room operators. The inspectors also noted that a recently completed operations department audit of all active OEs had failed to identify these inspector-identified issue As part of the follow up to the 21SW102 OE, the inspectors toured the five other similar valves at Units 1 & 2, and found another valve actuator (12 SW102) that also exhibited excessive air leakage. PSEG Nuclear personnel had not previously identified this condition and thus no action had been taken to address it. The inspectors informed

control room supervisors of this degraded condition and operators subsequently completed an OE identical to that employed f.or the 21SW102 valv R16 Operator Workarounds Inspection Scope (71111-16)

The inspectors reviewed the list of all operator workarounds*(OWAs) being tracked at the Salem units to assess their collective impact on plant risk and the operators' ability to effectively respond to plant events. There were 32 active OWAs between the two units at the time of this review. The inspectors also compared PSEG Nuclear's definition of OWA with that established in NRC guidance to determine whether there may be issues at Salem which met the NRC definition, but were not tracked as such by station operators. The monthly OWA assessment report was also reviewe Observations and Findings Neither PSEG Nuclear nor the inspectors identified any significant concerns as a result of aggregate reviews of all the active OWAs. Specifically, PSEG Nuclear maintained a list of active OWAs at the station and issued a collective assessment report of the various issues on a monthly basis. This assessment report included an evaluation of the aggregate impact of OWAs on both individual work stations and on individual plant systems. However, the inspectors noted that PSEG Nuclear did not assess the risk presented by the OWAs in terms of their effect on combinations of equipment that may collectively provide a success path for mitigating a postulated accident. The inspectors verified that PSEG Nuclear included all of the deficiencies associated with the OWAs in their corrective action progra The inspectors also determined that there were some issues at the station which met the broader NRC definition of an OWA and were not tracked, including:

  • isolation of 13 and 23 charging pumps due.to excessive seal leakage
  • logging of additional readings of Unit 1 auxiliary building differential pressure
  • manual (not automatic) starting of the 12 charging pump auxiliary oil pump required Further, PSEG Nuclear did not track compensatory measures (which require periodic operator action) associated with equipment operability evaluations or temporary modifications as OWAs. PSEG Nuclear noted that the NRC definition represented guidance but not regulation and acknowledged the inspectors' determination.
  • OTHER ACTIVITIES 40A2 Performance Indicator Verification Inspection Scope (71151)

The inspectors verified the accuracy and completeness of the data used to calculate and report the Reactor Coolant System (RCS) Leakage, RCS Specific Activity, and Containment Leakage performance indicators (Pis) for both Salem unit Observations and Findings From a review of March, April, and May 1999 RCS leakage and activity data, the inspectors determined that PSEG Nuclear personnel accurately reported the Pis using guidance contained in the Nuclear Energy Institute (NEI) draft Pl guideline document, 99-02, revision B. As of May 1999, both Pis were green at each unit with no adverse trends noted. The inspectors verified that the procedures used by technicians to obtain RCS leakage and activity measurements were technically adequate. Additionally, the inspectors reviewed several recently completed RCS leakage calculations and did not note any discrepancie The inspectors also reviewed the containment leakage information database and noted that it accurately tracked individual penetration leak rate test results. Through discussions with cognizant personnel, the inspectors determined that the containment leakage calculation methodology was appropriate, and that the Pl data was accurately reported in accordance with the above noted NEI guidance document. As of May 1999, the Pl was green at each unit with no adverse trends indicate The inspectors noted that a containment isolation valve in the service air system had failed its leak rate test in April 1999, such that a Unit 2 containment leakage value existed which exceeded the white threshold, i.e., greater than 60% of total allowable leakage. Technicians had promptly repaired and retested the valve with satisfactory leak rate results. PSEG Nuclear reported the total containment leakage rate as it existed at the end of April, rather than the maximum monthly value which would have included the initial service air valve failure data. The inspectors determined that this Pl reporting approach was consistent with NEI 99-02, draft revision B. PSEG Nuclear did report the degraded containment performance due to the service air valve failure in accordance with 10 CFR 50.72 and 50.73 (see section 40A3.a).

40A3 Event Follow-up (Closed) LER 50-311/99-002-00 and -01: Containment isolation valve failed lo_cal leak*

rate test - degraded containment integrity. This LER and supplemental report document a containment isolation valve leak rate test failure during the 1999 Unit 2 refueling outage. PSEG Nuclear determined the cause of the test failure to be from foreign material preventing the valve from completely closing. The valve was subsequently

repaired and retested satisfactorily. Immediate and proposed long-term corrective actions were adequate and were tracked in the corrective action progra {Closed) LER 50-272/99-003-00: Unplanned entry into technical specification (TS) 3. for the control room ventilation system. This issue was discussed in NRC Inspection Report 50-272&311/99-04. The inspectors determined that corrective actions were reasonable and were tracked in the corrective action progra {Closed) LER 50-272/99-004: Unplanned reactor trip due to a negative flux rate tri This event was discussed in NRC Inspection Report 50-272&311/99-04, and involved a dropped control rod that caused a negative flux rate reactor trip signal. PSEG Nuclear determined the most likely cause of the dropped control rod to be a rod control cable insulation defect combined with containment environmental conditions (i.e., moisture).

The root cause of the cable defect could not be determined. Followup actions for this event were adequate and included visual inspections of similar electrical conductors inside both the Unit 1 and 2 containment building {Closed) LER 50-272/99-005".'00: Containment fan coil unit (CFCU) out of service more than TS allowed outage time (AOT). This issue was discussed in NRC Inspection Report 50-272&311/99-04, and ultimately resulted in an NRC Notice of Enforcement Discretion prior to exceeding the applicable TS AOT. The LER revealed an additional potential cause for one of the various CFCU leaks. Specifically, maintenance department personnel removed a service water (SW) pressure transmitter from service that caused the inadvertent repositioning of a CFCU SW outlet valve. PSEG stated that this may have induced a pressure transient in the SW system that contributed to the CFCU leak {Closed) LER 50-311/99-006-00 and -01: High head safety injection flow balance discrepancy noted during surveillance. This issue was discussed in N'RC Inspection Report 50-272&311/99-04: No new issues were identified in this LE A4 Other Senior Management Reorganization On July 19, 1999, PSEG Nuclear LLC created four new senior management positions and assigned individuals as follows: Mark Bezilla, Vice President (VP) - Operations, Marty Trum, VP - Maintenance, Dave Garchow, VP - Technical Support, and Tim O'Connor, VP - Plant Support. Bert Simpson became Senior VP & Chief Administrative Officer. Harry Keiser and Lou Storz remained as President & Chief Nuclear Officer and Senior VP - Operations, respectively. The operations managers at both the Salem and Hope Creek stations report directly to Mr. Bezill *

40A5 Management Meetings Exit Meeting Summary On July 16, 1999, the inspectors presented their overall findings to members of PSEG Nuclear management led by Dave Garchow, General Manager of Salem Operation PSEG Nuclear management acknowledged the findings presented and did not contest any of the inspectors' conclusions. Additionally, they stated that no'ne of the information reviewed by the inspectors was considered proprietar Predecisional Enforcement Conference Summary

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On June 24, 1999, a predecisional enforcement conference was held at the NRC Region I office to discuss potential enforcement issues identified following a U.S. Department of Labor (DOL) administrative law judge decision against PSEG Nuclear. Specifically, the DOL judge had found that PSEG Nuclear management took adverse personnel actions against an employee who had raised a nuclear safety concern, which was an apparent violation of 10 CFR.50.7, "Employee Protection." The resulting NRC enforcement action associated with this matter was issued on July 28, 199 PSEG Nuclear/NRG Management Meeting On June 29, 1999, members of NRC Region I management, led by Randy Blough, Director, Division of Reactor Projects, met with members of PSEG Nuclear management led by Dave Garchow, at the Salem County Community Center in Salem, NJ. The meeting was open for public observation. PSEG Nuclear managers presented the status of several current issues of mutual PSEG Nuclear and NRC concern during the meetin Slides used in PSEG Nuclear's presentation are included as Appendix A to this repor *

  • Closed 50-272/99-003-00 50-272/99-004-00 50-272/99-005-00 50-311/99-002-00 50-311/99-002-01 50-311199-006-00 50-311/99-006-01

ITEMS OPENED AND CLOSED LER LER LER LER LER LER LER Unplanned entry into technical specification (TS) 3.0.3 for control room ventilation. (Section 40A3.c.)

Unplanned reactor trip due to a negative flux rate trip. (Section 40A3.b)

Containment fan cooler unit out of service more than TS allowed outage time. (Section 40A3.e)

Containment isolation valve failed local leak rate test. (Section 40A3.d)

Containment isolation valve failed local leak rate test (Supplement 1 ). (Section 40A3.d)

High head safety injection flow balance discrepancy noted during surveillance test. (Section 40A3.a)

High head safety injection flow balance discrepancy noted during surveillance test (Supplement 1 ).

(Section 40A3.a)

LIST OF.BASELINE INSPECTIONS PERFORMED The following baseline inspection procedures were implemented during the report perio Documented findings are contained in the body of the repor Procedure Title Report Number Section 71111-01 Adverse Weather Preparations 1R01 Elevated river temperature 71111-04 Equipment Alignment 1R04 Unit 1 CFCUs, Unit 2 service water 71111-05 Fire Protection 1R05 71111-09 lnservice Testing of Pumps and Valves 1R09 13 AFW pump, main steam atmospheric relief valves 71111-10 Large Containment Isolation Valve Leak Rate & Status Verification 1R10 Containment airlocks, purge & exhaust valves, and relief valves 71111-12 Maintenance Rule Implementation 1R12 71111-13 Maintenance Work Prioritization & Control 1R13 71111-15 Operability Evaluations 1R15 71111-16 Operator Workarounds 1R16 71111-19 Post Maintenance Testing 1R19 71111-22 Surveillance Testing 1R22 2A EDG, 22 containment spray pump, 1 C 125 V battery 71111-23 Temporary Plant Modifications 1R23 TMOD 98-009 (AFW tank connection)

71151 Performance Indicator Verification 40A2

AFST AFW AOT ASME CAP CCHX CDF CFCU CFR DOL EDG

.GTG IST LLC LER LERF M-Rule NEI NRC OE OWA PDR Pl PSEG RCS SW TMOD TS VP

LIST OF ACRONYMS USED Auxiliary Feedwater Storage Tank Auxiliary Feedwater Allowed Outage Time American Society of Mechanical Engineers Corrective Action Program Component Cooling Water System Heat Exchanger Core Damage Frequency Containment Fan Cooler Unit Code of Federal Regulations Department of Labor Emergency Diesel Generator Gas Turbine Generator lnservice Testing Limited Liability Corporation Licensee Event Report Large Early Release Frequency Maintenance Rule Nuclear Energy Institute Nuclear Regulatory Commission Operability Evaluation Operator Workaround Public Document Room Performance Indicator Public Service Enterprise Group Reactor Coolant System Service Water Temporary Modification Technical Specification Vice President

The Power of Commitment OPS~G June 29, 1999 NRC Presentation Salem Community Center AGENDA Introduction Dave Powell Performance Indicators Gabe Salamon Human Performance Improvement Initiatives Dave Garchow Corrective Action Program Changes SAP & Y2K Status Hope Creek Fuel Vendor Change Jerry McMahon Dave Powell Don Notigan

The Power of Commitment OPS~G June 29, 1999 NRC Presentation Performance Indicators Performance Indicators NBU Implementation of the New NRC Oversight Process

The Power of Commitment OPS~G

June 29, 1999 NRC Presentation Performance Indicators Major Activities

  • 11 Initial Data Acquisition 11 Stakeholder Communications 11 Formalized Process
  • Training & Education 11 Where Are We?

The Power of Commitment June 29, 1999 NRC Presentation OPS~G Performance Indicators P e r f o rm a n c,e.1 n d I c a to r S u m m *a r y D a ta D a t e

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M ltlgatlng Systems Cornerstone D G U n availability H P I U n av a Ila b ility AF W or R C IC U n av a Ila b illty R H R U n availability S a fe ty S y stem Function a I Fa ilu r.e s B arrler Integrity Cornerstone R C S S p e c if i c A c 11.v It y

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RCS Leakage C ontainm en! Leakage E m e r g e n c y P r e p a r e d n e s.s C o r n: e rs to n e Drill/Exercise Performance

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ERO Drill Participatio AN S * R e liability 0 ccupatlonal Radiation Safety Corners.to11e Exposure Control E ffectlvenes Pub lie Radiation Safety Cornerstone Radiological Effluent 0 ccurrence PhyslcalProtectlon Cornerstone Security Equlpm en! Perform.ance Index Screening Program Performance FFD Program Performance

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The Power of Commitment June 29, 1999 NRC Presentation Human Performance Improvement OPS~G Managing Human Performance To Top Quartile Performance.

  • REINFORCEMENT OF SAFETY
  • TRAINING OF STAFF
  • MANAGEMENT/SUPERVISORY OVERSIGHT.
  • SELF ASSESSMENT AND CORRECTIVE ACTION
  • The Power of Commitment OPS~G

June 29, 1999 NRC Presentation Corrective Action Program Changes CORRECTIVE ACTION PROGRAM CHANGES

The Power of Commitment OPS~G June 29, 1999 NRC Presentation Corrective 1Action Program Changes REFOCUSING THE CORRECTIVE ACTION PROGRAM

  • Streamline the corrective action program
  • M*aintain Current High Volume Low Threshold
  • Cornerstone to improved plaJ;It arid personnel performanc *Focus on risk-significant issue *

The Power of Commitment June 29, 1999 NRC Presentation Corrective Action Program Changes OPS~G SCAQ & CAQ are 1 OCFR50 Appendix B related issue New term "Quality Condition" used to identify and address all other condition *

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  • Implementation eCloseout Year 2000 Readiness Disclosure

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  • Internal Audit Services
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  • Nuclear Regulatory Commission e Industry Peer Review
  • Contingency* Planning Y2K Status Year 2000 Readiness Disclosure

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The Power of Commitment OPS~G June 29, 1999 NRC Presentation PSE&G Fuel Vendor Transition Status PSE&G Fuel Vendor Transition Status

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The Power of Commitment OPS~G

June 29, 1999 NRC Presentation PSE&G Fuel Vendor Transition Status *

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  • Changing Fuel Vendors
  • Safety Margin Improvements, FLJel Economics
  • Process Computer Replacement, Robust Fuel Design
  • Implementation in Hope Creek Cycle 10

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June 29, 19991 NRC Presentation PSE&G Fuel Vendor Transition Status *

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  • Complete Licensing An.alysis Models
  • New Core Monitoring System Delivered in July 1999
  • Initiate ABB Manufacturing Campaign 17
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