IR 05000354/1986048

Insp Rept 50-354/86-48 on 861014-1117.Violations Noted:Core Spray Pressure Transmitter E-21-N055H Found Isolated & Applicable Tech Spec 3.3.3 Action Statement Not Entered

ML20214W913
Person / Time
Site:	Hope Creek
Issue date:	12/01/1986
From:	Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20214W903	List: IR 05000354/1986048 ML20214W901 ML20214W904
References
50-354-86-48, NUDOCS 8612100457
Download: ML20214W913 (16)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

050354-860714-050354-860828 Report N /86-48 050354-860907-050354-860915-Docket 50-354 050354-860916-050354-86092&

License NPF-57 050354-86100?

050354-861003 Licensee: Public Service Electric and Gas Company 050354-861003-050354-861003-Facility: Hope Creek Generating Station 050354-861004-050354-861005-Conducted: October 14 - November 17, 1986 050354-861005-050354-861017-Inspectors: R. W. Borchardt, Senior Resident Inspector Resident Inspector D. K. Fi Allp kelq y, Lead Rea tor Engineer Approved: ( & -

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b L. NqfrholmT Chief, Projects Section 28 Date Inspection Summary:

Inspection on October 14, 1986 - November 17, 1986 (Inspection Report Number 50-354/86-48)

Areas Inspected: Routine onsite resident inspection of the following areas:

followup on outstanding inspection items, operational safety verification, surveillance testing, maintenance activities, engineered safety feature system walkdown, recirculation pump trip system, licensee event report followup, and Enforcement Conference. This inspection involved 195 hours0.00226 days <br />0.0542 hours <br />3.224206e-4 weeks <br />7.41975e-5 months <br /> by the inspector Results: This inspection identified a violation of Operations Department Administrative Procedure OP-AP.ZZ-108(Q), in that core spray system valves were not operated in a controlled manner. It should be noted that this situation removed the "C" core spray pump discharge pressure transmitter from the ADS logic circui Further information on this violation can be found in Section 6 of this repor The NRC is also concerned with the number of licensee identi-fied Technical Specifications violations. This inspection reviewed seven licensee identified violations. Although it is commendable that these violations were licensee identified, this area deserves prompt attention.

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8612100457 861208 PDR ADOCK 05000354 G PDR

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Details Persons Contacted Within this report; period,-interviews and discussions were conducted with members of the licensee management.and staff and various. contractor per-sonnel as necessary to support inspection activity.

4 Followup on Outstanding Inspection Items 2.1 Inspector Follow Item

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(Closed) Inspector Follow Item (86-26-04); Review Bisco Seal Werk Packag Prior to initial criticality, the licensee had completed

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the necessary corrective actions associated with the Bisco Seal defects described in a Bechtel Construction, Inc. letter dated April

! 28, 1986. The inspector witnessed portions of this repair activity, but the completed work packages were not ready for review. During

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this inspection period, the inspector completed the review of work packages, safety evaluations, and Bisco test reports. No discrepan-cies were identified and the inspector has no further question .2 Unresolved Item (Closed) Unresolved Item (85-66-01); Instrument calibration label The inspector was originally concerned that instruments in the plant

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Further review showed that tne instruments were actually in cali-

! bration, but since the licensee no longer used calibration labels, j the originally applied labels were misleading. The calibration schedule is maintained by a computer based program which eliminates

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the need for the labels. The inspector reviewed the current practice of instrument calibration and found that the misleading calibration i labels are being removed as the instrument is worked o It appears

that the plant staff understands this program and that it is not a source of confusion. The inspector will continue to monitor the licensee's removal of misleading labels and has no further questions

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at this time.

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2.3 Violation (Closed) Violation (86-30-02); Reactor Core Isolation Cooling System inoperable. The inspector reviewed the licensee's response dated August 27, 1986 to this violation, and verified that the immediate

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and long term corrective actions have been completed. Operations Department procedure OP-AP.ZZ-108, " Removal and Return of Equipment to Service," now requires that the action statement log sheet be com-pleted for all equipment removed from service regardless of the

, equipment's current operability requirement. The inspector will continue to monitor the operability of equipment and systems during routine inspections.

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. 3 2.4 10 CFR Part 21 Notification

On August 20, 1986, Louis Allis notified the NRC, by telephone, of a

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potential defect in the operation of Synchro-Start type ESSB speed

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switches used on the emergency diesel generators at Hope Cree Louis Allis submitted a 10 CFR 21 notification based on extensive

, on going quality problems with R10 series relays used in these speed f switches. The problems encountered include: 1)' intermittent contact I

closure caused by phenolic dust contamination and tarnish on surfaces of contacts; 2) high relay armature pull-in force required for con-l tact shutting; 3) relays would not operate due to open coil wires;

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and 4) stationary contact missing. Louis Allis's 10 CFR 21 notiff-cation included recommendations to test the speed switches for consistent proper relay operation, and for acceptable and stable

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contact resistance when the relay contacts are shu !

All four diesel generators at Hope Creek have been successfully

started during monthly surveillance tests and during cold and hot

, loss of offsite power tests conducted in September and October. In

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addition, the licensee has tested all speed switches using procedure IC-DC.ZZ-109(Q) Revision 2, which incorporates Louis Allis's 10 CFR i 21 recommendations. . The inspector observed bench testing of the "D"

, diesel generator speed switch, reviewed the 10 CFR 21 notification

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and the_ licensee's internal report, and discussed the issue with the system engineer. The inspector had no further questions and this item is closed.

. Operational Safety Verification

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3.1 Documents Reviewed

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Selected Operator's Logs

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Senior Shift Supervisor's Log

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Jumper Log

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Radioactive Waste Release Permits (liquid & gaseous)

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Selected Radiation Work Permits (RWP)

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Selected Tagouts

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Health Physics Watch Log i 3.2 The inspectors periodically toured the plant during regular and i

backshift periods. These tours included the control room, Reactor, Auxiliary, Turbine and Service Water buildings, and the drywell (when

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access is possible). During the inspection activities, discussions

were held with operators, technicians (HP & I&C), mechanics, super-

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visors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Tech- ,

. nical Specifications, and Station Procedure '

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3. On a daily basis, particular attention was directed to the following areas:

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Instrumentation and recorder traces for abnormalities;

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Adherence to LCO's directly observable from the control room;

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Proper control room shift manning and access control;

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Verification of the status of control room annunciators that are in alarm;

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Proper use of procedures;

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Review of Logs to obtain plant conditions; and,

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Verification of surveillance testing for timely completio . On a weekly basis, the inspectors confirmed the operability of selected ESF trains by:

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Verifying that accessible valves in the flow path were in the correct positions;

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Verifying that power supplies and breakers were in the correct positions;

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Visually inspecting major components for leakage, lubrication, vibration, cooling water supply, and general operating conditions; and,

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Visually inspecting instrumentation, where possible, for proper operabilit .2.3 On a biweekly basis, the inspectors:

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Verified the correct application of a tagout to a safety related system;

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Observed a shift turnover;

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Reviewed the sampling program including the liquid and gaseous effluents;

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Verified that radiation protection and controls were properly established;

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Verified that the physical security plan was being implemented by monitoring:

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1) Fixed and mobile guard post ) Personnel, vehicle, and package control into the protected are ) Protected area and vital area detection aid ) Compensatory action taken when a security barrier is degrade ) Use of photo identification badges within the protected are Reviewed licensee-identified problem areas; and,

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Verified selected portions of containment isolation lineu .3 Inspector Comments / Findings:

The unit entered this report period in operational condition 1 with the reactor operating at 20% power, in test condition 3 of the power

, ascension progra In inspection report 86-47, the inspector identified a concern pertaining to the accuracy of the Safety Auxiliary Cooling System (SACS) P&ID. In particular, for some branch connections, the as-built configuration did not agree with the P&ID. This concern was brought to the attention of the system engineer who initiated FQ JEG-001 to modify the SACS P&ID. The inspector had no further question At 3:57 p.m. on October 18, 1986, the reactor scrammed on low reactor vessel water level after an I&C technician installed a test box on the "A" reactor feed pump (RFP) flow controller. The test box caused both the "A" and "B" RFPs to run back to minimum flow causing a decrease in water level. The licensee's investigation determined that a wiring error had been made internal to the test box. All systems responded properly after the scram and water level was recovered prior to reaching the ECCS actuation setpoint. The test box wiring configuration was corrected prior to the continuation of power ascension testin A reactor water cleanup (RWCU) isolation occurred on October 19, 1986, while the blowdown rate was being decreased in order to increase reactor water level. The isolation was attributed to erroneous flow readings which satisfied system logic that a leak existed in the syste The erroneous flow readings were caused by entrapped air from a partially open blowdown isolation valve. After the isolation was determined to be invalid, it was reset and the RWCU system returned to normal operation.

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At 10.43 a.m. on October 19, 1986, the reactor was taken critical for continuation of the power ascension test program, specifically, feed pump controller tuning and HPCI operational testin The._ licensee declared the High Pressure Coolant Injection (HPCI)

system to be inoperable on October 22, 1986, after the HPCI'feedwater line injection valve (HV-8278) failed to open during a power ascen-sion test. An investigation determined that motor overloads for the injection valve were undersized. These overloads are bypassed during an automatic or manual start signal from the control room, but were in effect for a power ascension test of the local manual start capabilit The overloads were replaced and the HPCI system retested on October 23. The retest failed to satisfy the response time to reach rated flow acceptance criterion of 27 seconds. The measured response time was 28.23 seconds. The licensee completed further adjustments to the oil control system for the HPCI turbine throttle valve and on November 6, met the response time acceptance criterion with a time of 23.8 second On October 27, 1986, the licensee notified the NRC that licensee condition 12.a to operating license NPF-57 would not be completed on schedule. The license condition required PSE&G to. submit Detailed l Control Room Design Review Summary Report II to the NRC six months after completion of fuel load (October 27). The licensee eventually submitted this report on November 12, 198 At 5:40 a.m. on October 28, 1986, the licensee declared an unusual event and commenced shutting down the reactor when both HPCI and RCIC were declared inoperable. RCIC was declared inoperable on October 27 when it failed a surveillance test due to a faulty "B" channel high steam flow isolation transmitter. HPCI was declared inoperable when operators became aware of a recent gain adjustment to the HPCI flow controller and HPCI had not yet been demonstrated as operable through an appropriate retest. With both HPCI and RCIC inoperable, the licensee entered Technical Specification 3.0.3 at 4:50 The unusual event was terminated at 6:15 a.m. when RCIC passed its surveillance tes On November 1, 1986, the licensee experienced a "D" channel LOCA signal which initiated the "D" train of engineered safety feature None of the emergency core cooling systems injected water into the core. The LOCA signal was generated when an upstream isolation valve leaked by while an I&C technician was operating instrument isolation valve The licensee entered test condition 6 (TC-6) and attained 100% power on November 1 At 7:50 p.m. and again at 8:15 p.m. on November 11, 1986, a reactor water cleanup isolation was received while placing the "A" RWCU filter demineralizer in service. The isolation was caused by a high differential flow signal which inputs to the leak detection syste The isolation was reset and the RWCU system returned to servic .

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At 9:12 a.m. on November 14, 1986, the reactor scrammed from 97%

power after receiving a reactor vessel high pressure signal. The high pressure condition was caused by power ascension closure testing of a main turbine control valve. Before the control valve had reached its full closed position, the maximum combined flow limit was reached which prevented the necessary bypass valves from opening and resulted in the pressure increase. All systems responded as required and no automatic ECCS actuations occurre At 10:12 a.m. on November 14, 1986, the reactor building ventilation system (RBVS) isolated and the filtration, recirculation and venti-lation system actuated when a high radiation signal was received at a RBVS radiation monitor. The licensee believes that the increase in radiation levels was due to the crud burst caused by the scram. The airborne contamination leaked into the reactor building steam tunnel through a RWCU flange leak and caused the RBVS isolation setpoint to be exceeded. The isolation occurred before any release was mad The isolation was reset and the ventilation system returned to normal within an hou The licensee entered operational condition 4 (cold shutdown) at 6:35 a.m. on November 16 in order to repair the "B" RHR pump. The "B" RHR pump exhibited excessive motor current and high pump vibration during operation earlier in the da Preliminary troubleshooting indicate that the motor is operational, but the pump may have a bearing failure. The licensee stayed in a shutdown condition to complete repairs to "B" RHR pump and the RWCU flange lea On November 17, 1986, the licensee received a nuclear steam supply shutoff system isolation of reactor water cleanup and residual heat removal systems when an I&C technician pulled the wrong fuse while performing surveillance test IC-FT.AB-019. The fuse was replaced and systems returned to normal. All systems performed as expected for plant conditions (operation condition 4).

During this inspection period the inspectors paid particular atten-tion to the areas of control room environment and plant housekeepin The following brief discussion is based upon the impressions of the resident inspectors, region-based inspectors, and NRC management. The control room licensed operators have been found to display a profes-sional attitude and appearance, and are always aware of plant statu While the high number of overhead annunciators detracts from the operator's ability to monitor plant status, the operators have been found to know the up-to-date status of each alarm. The licensee is not satisfied with this annunciator situation and is investigating possible design changes. Considering that a power ascension test program has been in progress, the control room staff has done a noteworthy job in the areas of noise control and control room acces The use of the work control center, located outside of the control room, prevents excessive numbers of people from needing access to the control room and reduces the amount of time that the operators

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. 8 spend processing paperwor Control room access is adequately controlled through the practice of entering the control room via the shift supervisor's office and the use of floor boundary marking The control room appearance is generally neat and well organized with an occasional accumulation of test equipment at the back panel Radios are not used in the control room, nor is personal reading material allowed. Plant housekeeping received considerable attention toward the end of construction and the implementation of a formal ,

administrative program has been found to be reasonably effectiv Plant and corporate management conduct periodic tours of the station and have given housekeeping a high priorit No violations were identifie . Surveillance Testing During this inspection period, the inspector performed detailed technical procedure reviews, reviewed in progress surveillance testing as well as completed surveillance packages. The inspector also verified that the surveillance tests were performed in accordance with licensee approved procedures and NRC regulations. The inspector also verified that the instruments used were within calibration tolerances and that qualified technicians performed the surveillance test The following surveillance tests were reviewed, with portions witnessed by the inspector:

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IC-CC.BF-010 Scram Discharge Volume Level Test

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IC-FT.BB-014 Functional Test, Nuclear Boiler-Division 2 No violations were identifie . Maintenance Activities During this inspection period, the inspector observed selected maintenance activities on safety related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifi-cations, and appropriate industrial codes and standard Portions of the following activities were observed by the inspector:

Work Order Procedure Description 86-09-08-25-1 IC-PM.KJ-004 "D" Diesel Generator

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Speed Switch Calibration 86-07-16-137-7 MD-PM.PG-001 Low Voltage Breaker Cleaning and Preventive Maintenance No violations were identifie , _ _ . _ _ _ . .

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. 9 Engineered Safety Feature (ESF) System Walkdown The inspectors verified the operability of the selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built configuration. This ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriat The Core Spray system was inspecte ; During the inspection of the Core Spray system on October 22, 1986, a discrepancy was observed between the in-field valve labels and the Tagging Request and Inquiry System (TRIS) valve alignment sheet. The inspector observed that the instrument root valve for pressure transmitter E-21-N055H was identified as valve BE-V9992 on TRIS but labeled as BE-V9993. The instrument root valve for pressure indicator PI-4578C was labeled BE-V9993 but identified on TRIS as BE-V9992. Of more significance than the apparent administrative labeling /TRF error, was the fact that the isolation valve to PT-N055H was found to be shut. This transmitter pro-vides an input into the Automatic Depressurization System (ADS) logic to indicate that-the "C" Core Spray Pump has started and is available to inject water into the reactor vessel. Each train of the ADS logic is set up such that the ADS relief valves will not open unless either 1) both pumps in a Core Spray loop are running or 2) one of the two RHR (Low Pressure Coolant Injection Mode) pumps are running. In effect, having PT-N055H isolated prevented the possibility of the ADS logic being sat-isfied due to the Core Spray pumps. The Core Spray pressure transmitters are required to be operable by Technical Specification 3.3.3. A review of

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plant testing records indicates that the pressure transmitter was isolated October 20, 1986, after completion of inservice testing on the "C" Core

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Spray Pump. The licensee was not aware of this valve configuration and had therefore failed to enter into the applicable Technical Specification action statement. The inspector informed the licensee that the failure to enter the applicable action statement was a violation of Operations Department procedure OP-AP.ZZ-108, " Removal and Return of Equipment to Service." (50-354/86-48-02) It also appears likely that had this problem

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not been NRC identified on October 22, 1986, that the action statement would have been exceeded and Technical Specifications violated.

i An inspection of the "A", "B" and "D" Core Spray pump rooms identified similar TRIS vs. P&ID (M-52) discrepa cies, although the pressure trans-mitter isolation valves were open. It appears that the overlay drawings

, used by the operations department to hang valve identification tags were not in agreement with the revised P&ID which now shows instrument root valves. The TRIS valve lineup sheets were also developed using the overlay drawings. The licensee has decided that the P&ID is the base document and that the TRIS lineup sheets, valve labels, and Operations Department procedures will be updated to agree with the P&ID. The licensee's corrective actions will be reviewed as part of the violation followu . _ _ . _-- - - - _ _ . . - _ - _

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, 10 7. Recirculation Pump Trip (RPT) System 7.1 Design The Hope Creek RPT is an " energized to operate" system with logic arranged so that 2 out of 2 logic will trip each of the two series 4160 volt GE breakers (GE5HK350-1200 AMP). The 4160 volt breakers have a single coil for the ATWS trip. The trip coil circuits are powered from the 125VDC safety-related batter The level and pressure sensors, Rosemount 1153's, are environmentally qualified and documented in the licensee's EQ data submitta The logic and control circuits for the RPT can be tested on lin The breakers are tested when the reactor is off line or during a refueling cycle. The selection of trip set points, procedure instructions and present training is such that RPT inadvertent actuations will be minimize The operating procedure (0P-ED.22-101(Q)) is the document that pro-vides the guidance to the operators in the event the recirculation pump fails to trip on the high pressure or low low water level trip signals. The procedure instructs the operators to manually trip the recirculation pump The transients for the tripping of the recirculating pumps are analyzed in the facility Final Safety Analysis Report (FSAR). The consequences of these transients are well within the limiting tran-sient analysis in the FSAR. (Note: The licensee does not have a PRA or reliability number for this system).

The reactor protection trip system at Hope Creek is consistent with applicable requirements of 10 CFR 50.62 (ATWS Rule). This design and the operating procedures are based on guidance developed by General Electric and submitted to the NR .2 GE 4160 Volt Breaker (GE SHK350-1200 AMP)

The circuit trip that removes power from the recirculation pump motor is performed by two 4160 volt GE breakers in series. These breakers have a single trip coil which is activated on a low low water level or high pressure ATWS signal. The licensee has no history of failures with these breakers. A review of the Inspection Order (IO)

program data verified that no major failures of these breakers have occurre O

, 11 7.3 Surveillance The RPT surveillance testing requirements are listed in the licensee's 10 system. The test frequency for the components of the RPT system are also listed in the 10 program. The 4160 volt breakers are tested on a refueling cycle, while the instrumentation testing is performed on a monthly surveillance cycl .4 Maintenance The licensee has a formal maintenance program which includes both corrective and preventive activitie The component history is maintained in the trending program data files. Trending data reports are supplied to the various sections for information and required management actions. The trending program, procedure SA-AP.ZZ-048(Q), " Station Performance and Reliability Monitoring,"

establishes the trending and analytical progra The 10 procedure has data sheets, instructions, and management approval signature blocks as part of the data package issued by this syste .5 Reliability The licensee has not performed a reliability analysis of the RPT system nor have they performed a PRA of this syste .6 Quality Assurance A quality assurance program in conformance with the requirements of 10 CFR 50, Appendix B, was applied to the RPT design and components from the sensors to the trip coil of the GE 4160 volt breake .7 Equipment Qualifications The sensors, instrumentation, relays and switches have been qualified to assure that the RPT will perform its operation under conditions relevant to the postulated ATWS. The instrumentation racks are seismically installed and meet the design requirements for this site locatio .8 Channel Independence All components used to trip the recirculation pumps are independent .

and separate from components that provide the reactor protection function. Although the sensors for both the RPT and the RPS are located on the same instrumentation racks, there are redundant racks with the sensors arranged so that a failure of a rack-or of an instrument sensing line will not prevent a RP Diversity between the RPT and the RPS is achieved by design and verified by inspection .

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To maintaththe reliabilitV of the system, the licensee has the components of the RPT system in the preventive and corrective maintenance progi-ams with the data poing into the trending prog rm. There is no enhancement of the RPT planned 'at,ei,his

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1 7.10 Recorded Failure'hatps for the RPT System '

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Tnere have been no design changes issued to increase the reliability of the RPT system frca its present desig ,

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No unacce> table conditions were identifie . Licensee EvedtJeport Folbwup (

The licenstie submitted the"following event reports during the inspection period. All bf the reports were reviewed for accuracy and timely submission. Tne asterisked reports received additional followbp by the inspector for corrective action implementation. The (#) items identify

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reports which involve Technical Speciffhtions violation ~. ~

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LER 86-039-01 '"A' Channel LOCA Logic Actuation Supplement LER 86-061-01 Inadvertent HPCI System Initiation

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1. • LER 66-062-00 Failure to Sattsty Technicai Specification

, Su?veillance Requirenients for Leakage Detection Monitors

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1. i LER 86-066-00 Failure to Meet Main furbine Rypass System

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1. LER56-067-00 Inoperable Accident Monitoring Instrumentation

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LER 46-068-00 Failure to Comply With Radiation Monitoring-v Technical Specification

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LER 86-071-00 , Past Accident Sampli systeri Check Valves

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1. LER 86-072-00 Inoperable Reactor Building Exhaust Radiation Manitoring Instrument .

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, 13 LER 86-073-00 Containment Electrical Penetration Assembly Installation Error LER 86-074-00 Inadvertent Actuation of the "B" Control Room Emergency Filtration Unit When Connecting a Recorder LER 86-075-00 Inadvertent Actuation of the "B" Control Room Emergency Filtration Unit During Troubleshooting

LER 86-076-00 Inadvertent Automatic Start of "B" Emergency Diesel Generator

1. Special Report Seismic. Monitoring Instrument Inoperable For More 86-003 Than 30 Days

1. Special Report FRVS Vent Radiation Monitor Inoperable For More 86-004 Than 72 Hours LER 86-062 describes the process through which an operations procedure was incorrectly approved by the system engineer as an adequate substitute for the monthly functional surveillance test for the drywell floor and equipment sump flow monitor. The licensee's corrective action included completing the functional surveillance test before entering an operational condition requiring the drywell flow monitor to be operational. The licensee also revised station administrative procedures to require that, prior to use of an alternate procedure to satisfy Technical Specification requirements, concurrence must first be obtained from the department responsible for the alternate procedur LER 86-067 describes design deficiencies which resulted in several instruments being powered by a non IE power supply which should have been supplied by an uninterruptible power source. These instruments include the safety relief valve acoustic monitors, and recorders which monitor residual heat removal heat exchanger outlet temperature and reactor pressure vessel level indicatio Details of these events are discussed in section "E" of NRC Inspection Report 86-5 LER 86-071 details the identification of two post-accident sampling system (PASS) valves which failed a local leak rate test (LLRT). An investigation determined that these and two other PASS valves were installed with the flow path reversed through the valve and that heat tracing had exceeded the valves design temperature of 150 degrees The root cause of the valve installation problem was a lack of detail on the isometric drawings. The corrective action included reinstalling the four PASS valve in the correct configuration, performing the LLRT, and valve stroking pursuant to the Inservice Test Program. The PASS isometric drawings were also revised to include the necessary details regarding system flow directio .

, 14 LER 86-076 describes the inadvertent automatic start of the "B" emergency diesel generator (EDG). The diesel generator output breaker did not shu After verifying that the start signal was invalid, the EDG was shutdown and returned to the standby conditio No root cause could be established for this event. The licensee has installed recorders to continuously monitor "B" EDG start signals for a 90 day perio During the LER review, it was noted that seven LER events constitute Technical Specification violation However, these LERs are not being cited as violations as they meet the following 10 CFR 2 Appendix C criteria:

1) The events were licensee identified; 2) The events fit severity level four or five; 3) The events were reported; 4) The events were or will be corrected, including measures to prevent recurrence, within a reasonable time; and 5) The events were not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violatio . Enforcement Conference On November 17, 1986, an Enforcement Conference was held between Public Service Electric and Gas Company (PSE&G) and the NRC Region I staff in King of Prussia, Pennsylvania. The purpose of the Enforcement Conference was to review and evaluate PSE&G's corrective action program taken in response to several recently identified design deficiencies. The licensee discussed each of the following areas:

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Summary of corrective actions taken in response to the inoperative reactor building to torus vacuum breakers and the findings of the Augmented Inspection Team;

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Review of the root cause analysis of the above identified problems;

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Evaluation to determine if PSE&G has other broad areas which might have generic problems similar to the identified design deficiencie The Region I staff acknowledged PSE&G's corrective actions regarding the design deficiencies and had no further question The NRC is con-

ducting a final review of the design deficiencies prior to determining the l appropriate enforcement action. The list of attendees is provided as Enclosure (1) to this report.

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. 15 10. Exit Interview

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The inspectors met with licensee and contractor personnel periodically and at the end of the inspection period to summarize the scope and findings of their inspection activitie Based on Region I review and discussions with the licensee, it was deter-mined that this report does not contain information subject to 10 CFR 2 restriction .

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Enclosure 1 November 17, 1986 Meeting Between PSE&G and NRC Region I List of Attendees Name Title Organization W. F. Kane Director, Division of Reactor Projects NRC Region I J. M. Allan Deputy Regional Administrator NRC Region I S. D. Ebneter Director, Division of Reactor Safety NRC Region I W. V. Johnston Deputy Director, Division of Reactor NRC Region I Safety R. M. Gallo Chief, Reactor Projects Section 2A NRC Region P. W. Eselgroth Chief, Reactor Projects Branch 2 NRC Region I J. T. Wiggins Chief, Reactor Project Section IB NRC Region I L. H. Bettenhausen Chief, Operations Branch NRC Region I D. J. Holody Enforcement Specialist NRC Region I L. J. Norrholm Chief, Reactor Projects Section 2B NRC Region I R. J. Summers Project Engineer NRC Region I R. W. Borchardt Senior Resident Inspector, Hope Creek NRC Region I D. K. Allsopp Resident Inspector, Hope Creek NRC Region I C. A. McNeill Vice President - Nuclear PSE&G R. A. Burricelli General Manager-Engineering and PSE&G Plant Betterment R. S. Salvesen General Manager - Hope Creek PSE&G B. A. Preston Manager - Licensing and Regulation PSE&G R. F. Drewnowski Manager - Nuclear Systems Engineering PSE&G J. A. Nichols Technical Manager - Hope Creek PSE&G J. H. MacKinnon General Manager - Nuclear Safety Review PSE&G l

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