IR 05000272/1992003

Insp Repts 50-272/92-03,50-311/92-03 & 50-354/92-02 on 920209-0321.No Violations Noted.Major Areas Inspected: Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness & Security

ML18096A627
Person / Time
Site:	Salem, Hope Creek
Issue date:	04/08/1992
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18096A626	List: IR 05000272/1992003 ML18096A624
References
50-272-92-03, 50-272-92-3, 50-311-92-03, 50-311-92-3, 50-354-92-02, 50-354-92-2, NUDOCS 9204170034
Download: ML18096A627 (39)

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No /92-03 50-311 /92-03 50-354/92-02 License Nos. DPR-70 DPR-75 NPF-57 Licensee:

Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Facilities:

Salem Generating Station Hope Creek Generating Station Dates:

February 9, 1992 - March 21, 1992 Inspectors:

T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector S. T. Barr, Resident Inspector H. K. Lathrop, Resident Inspector I. B. Moghissi, eacto Engi (Intern)

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Approved:

J. e Inspection Summary:

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Inspection 50-272/92-03; 50-311/92-03; 50-354/92-02 on February 9 - March 21, 1992 Areas Inspected: Resident safety inspection of the following areas: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and licensee event reports and open item followu Results: The inspectors concluded that the facility was operated in a safe manner during this period. The inspectors also identified three non-cited violations relative to the Salem facility; and one unresolved item relative to the Hope Creek facility.

9204170034 920409 PDR ADOCK 05000272 G

PDR i

EXECUTIVE SUMMARY Salem Inspection Reports 50-272/92~03; 50-311/92-03 Hope Creek Inspection Report 50-354/92-02 February 9, 1992 ~March 21, 1992 OPERATIONS (Modules 60710, 71707)

Salem: The Salem units were operated in a safe manner. Radiation monitoring J)ystem actuations were reported, and licensee response actions were appropriate. Unit 2 reactor core reload activities were conducted in a conservative manner. Operators responded well to a trip of the No. 2B 230/460 volt vital bus and to diesel generator test failures. Operating crews coordinated complex surveillance tests from the control room in a very controlled, deliberate manner. Operators responded appropriately to an inadvertent safety injection, caused by licensed operator error and a procedure weakness. Pre-outage work related to the Unit 1 control room modification was a potential distraction to control room* perssonnel, and required the operators to periodically stop work when noise and activity levels became disturbing. Weaknesses were identified with the quality of licensed reactor operator narrative log Hope Creek: The unit was operated in a safe manner. An emergency core cooling syst initiation during design change implementation occur.red, and the reactor vessel injection was promptly terminated and reset. Preparations to assure reliable decay heat removal capability during the outage in March 1992 were thorough and conservativ RADIOLOGICAL CONTROLS (Module 71707)

Salem: The inspector periodically observed station workers and Radiation Protection personnel implementing radiological controls and protection program requirements and did not identify any deficiencies. Radiological controls for the Unit 2 containment building were observed to be well implemented. Licensee followup for a spread of contamination in the auxiliary building, due to deficient protective equipment and substandard work practices, was thorough and timely. Radiation Protection personnel response to an Unusual Event, in which an injured contaminated individual was transported to a local hospital, was appropriat Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiological controls and protection program requirements did not identify any <leficiencl.es. Support of the March 1992 outage was well planned and effective in minimizing personnel exposure and contamination. An aggressive exposure goal was met despite significant emergent work. An inadvertent release of sodium hypochlorite to the Delaware River was appropriately handled; no radioactive release occurred.

MAINTENANCE/SURVEILLANCE (Modules 61701, 61726, 62703, 70313)

Salem: No deficiencies were identified through routine observations. Failure to follow a

. surveillance procedure resulted in a reactor coolant system (RCS) leak inside containment during subsequent RCS fill and vent activities, which is a non-cited violation. A loss of the No. 2B 230/460 volt vital bus and subsequent engineered safety feature actuation occurred due to technician error involving the incorrect installation of overcurrent protection relay Several complex surveillance tests were performed in conjunction with preparing Unit 2 for restart. While the test procedures, which had just recently been revised by the Procedure Upgrade Project, contained several technical errors, the tests were conducted in a planned and controlled manner upon revison. Ineffective communications between operations and chemistry personnel resulted in a missed and a late Technical Specification (TS) required surveillance chemistry sample, which is a non-cited violation. A steam generator blowdown flow transmitter TS reguired surveillance was missed due to a misclassification of the.

associated surveillance activity, which is also a non-cited violatio Hope Creek: Routine observations did not identify any deficiencies. Maintenance and

_surveillance activities in preparation for and during the-execution of the March 1992 outage*

were well planned, reflected a strong safety conscious approach and were performed in a quality manne Clos~ cooperation between all groups was a major factor in the outage's success.

EMERGENCY PREPAREDNESS (Module 71707)

Licensee response to two Unusual Events was appropriate. An Unusual Event was declared*

at Salem when a contaminated injured individual was transported to a local hospital. An Unusual Event was declared at Hope Creek due to an inadvertent emergency core cooling system actuation and initiation (with vessel injection). Both Unusual Events were properly classified, and notifications were made as required* by procedure SECURITY (Module 71707)

.Routine observation of protected area access and egress showed good control by the license No deficient conditions were identifie iii

ENGINEERING/TECHNICAL SUPPORT (Module 71707)

Salem: The inspector reviewed the 'management of engineering work activities and determined that they were being performed in accordance with applicable procedures, as well as being properly prioritized and executed. An engineering evaluation, previously conducted to support a seismic gap seal concern, still remains incompleted while the licensee continues evaluation of the effect of a missing seal on certain perevious equipment operability determination Hope Creek: The inspector reviewed the management of engineering work activities determined that they were being performed in accordance with applicable procedures, as well as being properly prioritized and executed. The inability of a high drywell pressure signal to automatically start the high pressure coolant injectiori system at low reactor pressure is unresolved. A design change to prevent spurious. starts of the two standby filtration recirculation ventilation system fans was successfully implemented during the March outag Plant managment and the safety evaluation appropriately addressed the safety aspects of the

. Design Change Packag SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 71707, 90712, 90713, 92701, 94702)

Salem: Several NRC items were closed this inspection period in various functional area Most licensee event reports were good; however, one supplement did not fully address the postulated event's consequences and is being resubmitted. The licensee appropriately responded to a Technical Specification inconsistency concerning diesel generator" operability while in Modes 5 and Hope Creek: The resident inspectors performed Temporary Instruction 2515/113, "Reliable Decay Heat Removal During Outages". The licensee program for shutdown risk management was determined to be extensive, incorporating many industry initiatives and recommendations. A number of licensee shutdown risk initiatives were successfully tested

. during the March 1992 outage.

IV

• SUMMARY OF OPERATIONS Salem Units 1 and 2 j

Unit 1 operated at or near 100% power for the entire inspection period. Preparations continued for the unit's tenth refueling outage, scheduled to begin on April 4, 199 Unit 2 continued activities associated with its sixth refueling outage throughout the entire report period. During the period, fuel was reloaded into the reactor vessel, and Mode 6 (Refueling) and Mode 5 (Cold Shutdown) were entered on February 16 and February 27, 1992, respectively. At the end of the period, preparations were underway to conduct the containment integrated leak rate test and establish Mode 4 (Hot Shutdown) condition.2 Salem Unit 2' Turbine Generator Replacement Status At the end of the inspection period, all main turbine units were assembled, and rotor alignments were completed. The three low-pressure rotating elements were replaced with spare units. New generator stator and rotor elements were also installed. *The licensee was in the process of coupling the turbine and generator elements. Related system modification implementation was performed this outage and included the following:

addition of a new filter in the auto-stop oil supply system to prevent clogging of orifices in the auto-stop system;

installation of a new pressure gauge for the portion of auto-stop oil system that is isolated during front standard test;

repositioning of the front standard auto-stop test gauges relative to human factor concerns;

installation of a new auto-stop solenoid valve in the unisolated portion of the system to allow testing without bypassing the turbine trip inputs to the auto-stop system; and,

circuit modifications to permit independent functional testing of each solenoid control devic Each of the planned modifications include system functional/operability testing. Other turbine-generator and support system functional testing, in addition to normal unit startup testing, includes flow balancing of stator water system, seal oil, and generator hydrogen gas makeup systems, generator phase-sequence testing, exciter and voltage regulator testing, and a turbine-generator unit torsional and amplitude test. The generator exciter was refurbished and is onsite. A schedule was established to complete operational turbine-generator testing to support power operatio *

2, Hope Creek Hope Creek operated at powet throughout the report period except for a scheduled mid-cycle maintenance outage from March 7 to March 16, 1992. At the time of the shutdown, the unit had operated continuously for 300 days. Major work accomplished during the outage included the replacement of the "A" reactor recirculation pump No. 2 seal, repacking a number.of valves in the main steam tunnel, *emergency diesel generator inspections, and design change implementations. The unit was restarted on March 15, 1992, and the generator was synchronized on March 17, 199.

OPERATIONS 2.1 * Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirements. Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical*

Specification compliance, and review of facility records. These inspection activities were conducted in accordance with NRC inspection procedures 60710 and 71707. The inspectors performed normal and back-shift inspections, including deep back-shift (29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br />) inspections as follows:

February 9, 1992 February io, 1992 March 15, 1992 March 15, 1992 March 16, 1992 Inspection Hours 6:00 p.m. - 12:00 :30 a.m. - 7:30 :45 a.m. - 3:30 :00 p.m. - 12:00 :00 a.m. - 7:30 a.m. * InspectiOn Findings and Significant Plant Events 2.2.1 Salem Unit 2 Core Reload The licensee reloaded fuel into the Unit 2 reactor core during the period of February 16 through February 19, 1992. Unit 2 entered Mode 6 (Refueling) as the sixth refueling outage was nearing completion. Westinghouse personnel performed the fuel movement acti~ities from the refueling bridge in the containment and in the spent fuel.handling building area They also provided coverage in the control room and at the nuclear instrumentation cabinet PSE&d licensed operators and reactor engineering personnel were also present at the required locations to _provide oversight, command, and contro *~*.

On February 18, 1992, at 2:02 p.m., a fuel assembly was inserted into core location C-1 During assembly placement, one source range monitor (N31) increased from 25 counts per *

second (CPS) to 100 CPS. The other source range monitor (N32), which was closer to the C-13 grid location, remained steady at about 20 CPS. The PSE&G senior reactor operator (SRO) on the refueling bridge ordered the fuel assembly removed to the spent fuel poo N31 channel spikes continued to occur for about 45 minutes after removal of the assembl Subsequently, the licensee declared the N31 source range channel inoperable and ceased all further fuel movement. Channel functional testing and troubleshooting activities did not find any problems or abnormalities. The licensee did note that welding activities were in progress in the containment and penetration areas. Licensee reactor engineering personnel also reviewed a plot of source range CPS versus time from the safety parameter display system (SPDS) computer. This SPDS plot did not show evidence _of a reactor power excursion due*

to reactivity changes. The licensee subsequently concluded that the N31 spiking was caused by electrical interference due to welding activities. Upon verification, the N31 channel was subsequently declared operable, and core reload was completed without incident. The licensee documented this event wit!) an incident repor The inspector reviewed core reload activities, including preparations, procedural adequacy and implementation, contractor and licensee personnel knowledge, communications, Technical Specifications, command and control, nuclear instrumentation operability, inverse count rate ratios and plotting, and incident report review. Selected personnel, including the SRO involved in the N31 count rate increase event, were interviewed. The inspector concluded that the licensee was conservative in its approach to, and conduct of, core reload activities. Nuclear safety was thoroughly demonstrate Test Failures of the No. 2A Emergency Diesel Generator (EDG)

On three occasions, problems occurred associated with EDG start attempts and/or surveillance test runs. Two of the events were preliminarily determined to be valid test failures, while one event was determined to be a non-valid test failure. The licensee is required per Technical Specification (TS) 4. 8.1.1.4 to submit to the NRC a written report of both valid and non-valid failure On March 2, 1992, during a 24-hour surveillance test for the No. 2A EDG, a jacket water cooling system leak occurred. Subsequently, the EDG was manually shut down and the test was terminated. The licensee determined that the leak was due to a failed (cracked)

• compression fitting and was in excess of the makeup capability of the jacket water cooling system. The fitting was replaced, and the EDG testing activities subsequently continue The liCensee determined that the event was a valid No. 2A EDG failur On March 4, 1992, following completion of the 24-hour surveillance test, the licensee attempted to start the No. 2A EDG from the safeguards equipment cabinet (SEC). TS 4.8.1.1.2 requires that the EDG be started from the SEC using a test signal within five

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minutes after completing the 24-hour test. The EDG did not start after operators depressed the SEC test push-button (A-1) as directed by surveillance procedure No. S2.0P-ST.DG-0012(Q), "2A Diesel Generator Endurance Run."*

During the current outage, an EDG start test push-button (E-2) was added to the SEC for surveillance testing purposes. That function was previously accomplished with the A-1 push-button. However, the procedure was not revised to n~flect the recently implemented modification, therefore, the EDGdid not start when A-1 was depresse T~e cause of the procedure not being revised was personnel error in that the responsible system engineer failed to include the surveillance procedure in the list of procedures affected by the modification. The procedure was subsequently revised and the test was satisfactorily

• performed. Additionally, a review was performed to ensure that other affected procedures were properly reviewed. No additional deficiencies were identified. The licensee determined that this event was a non-valid test failure of the No. 2A ED On March 5, 1992, the No. 2A EDG automatically tripped during the start of a surveillance test. Subsequent licensee investigation identified that the shutdown coil within the EDG governor had failed. The 2A EDG was recently overqaulect, which included the installation of a new governor. The failed governor was subsequently replaced with a rebuilt spare, and the EDG was successfully retested. The.Jicensee plans to send the governor (manufactured by Woodard) to an off site vendor for failure analysis. The licensee did not. experience similar governor operational problems with the remaining two Unit 2 EDGs or any of the

. three Unit 1 EDGs. The licensee determined that this event was a valid No. 2A EDG test failur The inspector reviewed the above events and concluded that the licensee's. actions, including.

TS Action requirement implementation and corrective actions, were appropriate. The special report required by TSs for the above three events will be reviewed upon submitta * Open Item Followup (Closed) Unresolved Item 50-272/90-19-03. Reactor coolant system (RCS) leakage rate determination did not periodically reverify quantified RCS leakage rates. The licensee revised the appropriate procedures to state that quantified (by physical measurement) leakage rates may be utilized to perform water balance inventory surveillances only if they have been *

quantified within the last 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This procedure modification resolved the concern, and this item is closed.

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5 Radiation Monitor Engineered Safety Feature (ESF) Actuations The following ESF actuations occurred and were reported by PSE&G during the period:

Unit Radiation Monitor Date Time

Unknown - Train B February 24, 1992 2:19 lRllA March 6, 1992 7:26 R1B March 15, 1992 11:05 R1B March 19, 1992 8:12 * The above listed events continue to be indicative of the degraded radiation monitor-system (RMS). Systems responded as designed causing containment ventilation and/or control room ventilation system isolation and start signals. The cause(s) of the February 24, 1992, control room ventilation isolation signal was. unknown; however, the Train B logic was initiate The ventilation system was already in the recirculation mode of operation; therefore, no actual damper realignment occurred.. The March 6, 1992 event* was the result of an electrical spike on lRllA. Previously initiated licensee corrective actions included short term and long term equipment upgrades. The inspector reviewed the licensee actions taken in response to these specific events, and no unacceptable conditions were note The Unit 2,March 15, 1992, event is discussed in Section 4.3.1.C of this report. The Unit 2 March 19, 1992, event occurred during electrical system transfer activities associated with surveillance testing when power was lost to the radiation monitor. The monitor was subsequently restored to service. Licensee investigation was continuing at the end of the inspection period. The inspector will review the results of the investigation and the associated licensee.event report upon submitta Pre-Outage Work Performed While Unit 1 Operating On March 13, 1992, during a control room tour, the inspector observed ari activity associated with a plant modification which represented a potentially significant distraction to the control room operators. Specifically, pre-outage work was being performed for a Unit 1 control room modification to suppport the refueling outage scheduled to begin April 4, 199 The work was being done *with the unit operating at 100% power. The work included -

removal of the existing carpet with a long handled scraper and installation. of a large support base plate for a temporary annunciator panel. The inspector observed approximately five personnel involved with the work which fovolved a certain amount of noise and distractio At the time of the observation, work was being completed for that day.* The inspector subsequently notified operations management of the concern relative to possible operator

~istraction and the potential for the workers to initiate a plant event-by bumping adjacent

equipmel}t. The licensee acknowledged the comments and indicated that the work was authorized on the basis that plant safety would not be impaired or the control room operators unduly distracte *

On March 18, 1992, the inspector observed that the large, temporary annunciator panel had been installed (seismically mounted) and that additional carpet removal activities were being performed. The temporary annunciator panel will be used during the control room modification when the entire overhead annunciator system will be taken out of service. The carpet removal activities on March 18, 1992, again represented an apparent significant distraction to control room operators. The inspector questioned the control room operators on March 20, 1992, who stated that they stopped the pre-outage work on several occasions due to the distraction it presented during certain operational activities. The inspector concluded that this action taken by the operators was appropriat The inspector determined that the pre-outage control room activities could have posed an undue distraction to the operators and introduced an unnecessary risk of affecting plant operations. The inspector expressed these concerns to station management on March 20, 1992. Management personnel indicated that routine activities of this type would be more thoroughly evaluated relative to the effect on operating personnel. Since this appears as an isolated instance, the inspector had no further questions on this matter at this time. Quality of Licensed Operator Narrative Logs During periodic reviews of reactor operator (RO) narrative logs, the inspector identified several examples in which the log entries were either incomplete or unclear. One example

• included the failure of an operations coordinated surveillance test, No. S2.0P-ST.DG-0012(Q), 2A Diesel Generator (DG) Endurance Run. II There was no log entry noting the failure of the diesel generator to start upon a manual demand during testing. Another example was when *log entries related to several occasions when different DGs were out of service at different times between February 28 and March 5, 1992. The logs were unclear as to why the DGs were operated or shutdown, and whether testing results were satisfactor The inspector discussed the above concerns with the Operations Engineer (OE) who

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acknowledged that weaknesses existed with respect to the overall quality of RO narrative logs. The OE stated that the training department and operations staff were in the process of reviewing ways to improve the _quality of the logs. For the interim, increased management attention would be provided to enhance the quality of the RO logs. The inspector will monitor the effectiveness of the licensee's actions during daily RO log reviews.

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2.2.2 Hope Creek Inadvertent Emergency Core Cooling System (ECCS) Initiation and Reactor Vessel Injection On March 8, 1992, following a plant shutdown for a scheduled maintenance outage, a "B" channel loss of coolant accident (LOCA) logic signal was received which started the "B" emergency diesel generator (EDG), the "B" residual heat removal (RHR) pump, and the "B" core spray (CS) pump. At the time, the reactor was in Cold Shutdown (Operational Condition 4) with reactor water level +69 inches. After verifying that no valid ECCS signal existed, the two pumps and EDG were stopped, and reactor vessel injection was terminate Reactor vessel level had increased to +82 inches. An Unusual Event (UE) was declared at 5:32 p.m. due to the ECCS actuation with reactor vessel injection., After resetting the initiation signal and restoring the EDG and ECCS equipment lineups to normal, the UE was terminated at 5:36 *

The licensee determined that the initiation signal had been caused by a maintenance I&C technician while implementing a design change package (DCP 4HC-0202/14), involving the installation of test jack boxes on the outside of scram sensitive/safety related panels. While terminating leads inside the electrical panel, the technician inadvertently rotated a holding plate, which shorted across a _bus bar, sending an electrical spike through the "B" LOCA initiation logic and causing the initiation signa The inspector reviewed the licensee's actions relative to the installation of DCP 4HC-0204/14 and concluded that reasonable precautions to prevent such an occurrence had been take Lessons learned from several previous similar events had been incorporated in the licensee's approach to this installation. The work was delayed until the unit was shut down due to the scram risk involved. A thorough briefing had been conducted wherein special emphasis was placed on the potential for electrical shorts and grounds, and the need for close attention to detail. The technician had used electrical tape to cover any exposed leads and was careful in maneuvering the leads inside the panel. The cramped working conditions, poor lighting, and close spacing on the terminal strip were contributing factors. The inspector concluded that although this event occurred, the above actions appeared to be appropriate to minimize the likelihood of this event. Licensee event followup was determined to thoroug Preparations For March 7, 1992 Maintenance Outage and Assurance of Decay Heat Removal Capability In February 1992, the licensee decided to schedule a short "mini"-maintenance outage prior to the summer peak electrical generation/demand period. A similar outage had been performed at Salem Unit 2 in 1991 which had allowed the unit to operate successfully through the summer and early fall. Major work to be accomplished in Hope Creek's outage (March 7-16, 1992) included:

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repairing valve stem packing leaks in the main. steam tunnel, inspection/replacement of th~ "A" reactor recirculation pump No: 2 seal,

"B" service water loop discharge valve and piping upgrades, implementation of a design change to prevent spurious starts of the "E" and "F" filtration, recirculation and ventilation system (FRVS) fans, and emergency dies~l generator inspections/corrective maintenance.

The inspector reviewed the actions taken by the licensee to safely shut down the unit and maintain reliable and redundant means to remove decay heat. (A discussion of shutdown risk management is found in Section 8.2.A of this report.) The primary means of decay heat rem*oval was via the "A" and "B" residual heat removal (RHR) pump/heat exchangers, which share a common suction line from the reactor recirculation system. Precautions were taken to assure that the in_ board and outboard suction isolation valves would not close shoul electrical power be inadvertently lost. Also, a redundant means of decay heat removal was available* to the operators using the core spray pumps and the main steam safety relief valves and recirculating the water inventory through the torus. Engineering calculations indicated that a minimum of 17.39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> was available following a loss of the RHR system for reactor temperature to reach 200 degrees F, using worst case initial parameter Licensed operators received additional training on *shutdown operations, including inadvertent criticality and loss of shutdown cooling. Abnormal procedure OP-AB.ZZ-0142(Q) contained clear and well written guidance for restoration and the use of alternate means of decay heat removal, including the method described above. The inspector noted that operators appeared knowledgeable of the contents of the procedure and the options available to the Operators took prompt and effective action in terminating the emergency core cooling initiation and vessel injection which occurred on March 8, 1992 (See Section 2.2.2 A).

Reactor water level increased from +69" to +82". This volume increase (about 3000 gallons) had no impact on plant activities and injection was terminated prior to reaching the main *steam lines ( + 118").

As an aid to operations and other personnel involved with the outage, an equipment/systems status list was updated and distributed on a shiftly basis. The list contained the equipment and systems required to be operable to* ensure plant safety and containment integrity. This initiative appeared to have been well-received by plant personnel. During plant tours, the inspector noted the current list posted in many work areas. Based on its acceptance, the licensee indieated that this approach would be incorporated in future outage In summary, the _inspector. concluded that the licensee had been through and conservative in their evaluations of shutdown risk and the actions taken to assure reliable decay heat removat. Operators appropriately handled an ECCS injection and appeared knowledgeable in shutdown operations and measures to maintain a decay heat removru capability.

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9 Unit Restart and Power Ascension The Hope Creek unit restarted on March 1s; 1992. The inspector observed reactor criticality

. from the control room. The inspector verified procedure usage, management and supervisory oversight, and operation activitie The inspector also observed the plant heatup, integrated system testing, turbine startup and *

generator synchronization, and power ascension. The inspector concluded that operations personnel were conservative and nuclear safety conscious during these evaluation.

RADIOLOGICAL CONTROLS 3.1 Inspection Activities PSE&G' s conformance with the radiological protection program was verified on a periodic *

basis. _These inspection activities were conducted in accordance with NRC inspection procedures 71707 and 9370.2.1 Salem Unit 2 Containment Tour Prior to core reload activities (see Section 2~2.1.A), on February 14, 1992, the inspector toured the Unit 2 containment. Areas inspected included the refueling area-on the 130 foot level, the annulus area, and inside the biological shield. Items checked included

- housekeeping and cleanliness, work in progress, and radiological controls. Overall, housekeeping and cleanliness was good. The inspectors did note moisture on the floors, walls, and equipment surfaces. The inspectors questioned licensee personnel who stated that high humidity concurrent with purge ventilation being out of service was the cause. The

• inspector further discussed this item with the senior nuclear shift supervisor who stated he was aware of the situation and that purge ventilation work was nearing completion. The inspector concluded that appropriate attention was provided to the return to service of the ventilation syste * Spread of Contamination in Auxiliary Building On February 25, 1992, a portion of the Unit 2 auxiliary building floor was inadvertently contaminated during the transport of a contaminated filter. The filter was used during a reactor cavity draindown activity. The licensee's preliminary investigation identified the root causes of the area contamination to be inadequate communications, deficient protective equipment, and substandard work practices. The filter was placed in a barrel containing two

• plastic bags; however, the bags were not taped closed. Additionally, pdor to the subsequent transport of the enclosed cart, the barrel containing the filter was placed on its side, and the

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contaminated liquid leaked from the cart onto the floor. About a 1000 square foot area was contaminated* within the auxiliary building. One minor personnel clothing contamination resulte The licensee isolated the affected area and completed a decontamination activity. Other licensee actions included *developing a detailed checklist for transporting contaminated equipment and stressing conformance with station work standards. The inspector reviewed the licensee's draft radiological occurrence report (ROR) No. 92-41 and did not identify any additional deficiencies. *The inspector concluded that the licensee's short term corrective actions were appropriate and had* no further questions at this tim.2.2 Hope Creek Mini-Outage Perf onnance The inspector observed several activities requiring radiation protection support during the nine-day maintenance outage from March 7 _to March 16, 1992 and noted the following:.

Repacking of numerous valves in the main steam tunnel was well-coordinated and

• controlle Replacement of the "A" reactor recircufation pump No. 2 seal was well-planned and executed. The total dose received by maintenance personnel was less than estimate :Personnel involved demonstrated good ALARA techniques.. *

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Drywell access control was efficient, keeping access to an "as-needed" basi *

An aggressive goal of less than 12 pe,rson-Rem for the outage was achieved. There were four personnel contamination events, but none were repetitive~ despite several high-risk activities (pump seal replacement and steam tunnel valve work).

Based in part on the above, the inspector concluded that the licensee had demonstrated an effective and well-planned approach to minimize personnel exposure and contaminatio Inadvertent.Chemical Release to the Delaware River On March 9, 1992, following a u*nit shutdown for a maintenance outage, licensee personnel discovered that the station service water (SSW) hypochlorination system was pumping into the "D" service water pump bay (the "D" pump was not in operation).. Investigation

.revealed that valve 1EQ HV-7817D had failed to automatically close when the "D" SSW pump had been removed from service. Upon discovery, the manual isolation valve upstream of HV-7817D was".closed, terminating the flow into the "D" bay. Notifications were properly made to the NRC and the State of New Jersey. The resident inspector was informed at home. Preliminary results from an evaluation of the incident indicated that a

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sodium hypochloride solution of 30-50 ppm concentration had been flowing into the "D" bay

• for about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. No. abnormalities were noted in the river water outside the service water pump* house. Since the adjacent SSW pump was in service, the licensee felt that most of the

• chemical would have been entrained in its suction flow and pumped into the service water loop. The inspector concluded that the licensee had responded appropriately and that the safety significance was minimal since no. radioactive release had occurred; MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on* safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards. These inspections were conducted in accordance with NRC inspection procedures 61701, 61726, 62703 and 7031 Portions of the following activities were observed by the inspector:

Salem 2 Salem 2 Salem 2 Hope Creek Work Order (WO) or Design Change Package WO 920107065 2SC-2267 2EC-3048 WO 920226021 Description Remove and inspect CS-2 valve stem nut and spring pack Safeguards equipment cabinet (SEC)

electronics upgrade

. Upgrade of 4kv vital bus undervoltage relays Change high pressure coolant injection

. jockey puinp bearing oil The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra.2 Surveillance* Testing Inspection Activity The inspectors performed detailed technicaI procedure reviews, witnessed in;...progress surveillance testing, and reviewed completed surveillance packages. The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications,

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approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedures 61701 and 6172 The following surveillance tests were reviewed, with portions witnessed by the inspector:

Unit Procedure N Test Salem 2 S2.0P-ST.SJ-0014(Q)

Intermediate Head - Cold Leg Throttling Valve Flow Balance Verification Salem 2 S2.0P-PT.CS-0013(Q)

Differential Pressure Test (No Flow) of Containment Spray Pump* Discharge Stop Valves 21CS2 and 22CS2

Salem 2 S2. OP-ST.SSP-OOOl(Q)

Manual Safety Injection Test - Solid State Protection System Salem 2 S2. OP-ST. SSP-0002(Q)

Engineering Safety Feature - Manual Safety Injection SEC Section - 2A Vital Bus Salem*2 S2.0P-ST.SSP-0003(Q)

Engineering Safe~y Feature - Manual Safety Injection SEC Section - 2B Vital Bus Hope Creek OP-FT.AC-0001 Main Turbine* Functional Test - Weekly Hope Creek OP-ST.KJ-0001

"A" Emergency Diesel Generator Monthly test Hope Creek IC-FT.AB-019(Q)

Main Steam Isolation Input to Reactor *

• Protection System The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing program.

13 Inspection Findings 4.3.1 Salem

• Open Item Followup (Closed) Unresolved Item (50-311/90-04-01). Unit 2 steamline isolation event during testing while shutdown. The licensee completed their review and submitted Licensee Event Report (LER) 90-07. The LER was reviewed and determined to be acceptable during NRC Inspection 50-311/90-0S. The licensee concluded that root cause was an inadequate procedure, for which appropriate corrective action has been implemented. Based on this review, the unresolved item is close (Closed) Unresolved Item 50-272/90-81-03. Emergency diesel generator (EDG)

surveillance performed with instrumentation being out of service. The instrumentation involved were temperature indicating pyrometers and were not used to verify EDG operability. Rather, the pyrometers were used for performance monitoring and trending purposes. The licensee revi.sed the affected surveillance procedures to clearly indicate which measurements are needed to verify EDG operability. Additionally, the pyrometers were being replaced with more reliable indicators. The inspector reviewed the licensee's actions and had no further questions. This item is closed.

(Closed) Unresolved Item 50-272/90-200-04. Lack of a detailed procedure for a complex emergency diesel generator maintenance activity. A specific maintenance procedure was

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subsequently developed by the licensee. In addition, the licensee had been in the process of developing similar specific procedures as needed for important tasks. The inspector reviewed the associated procedure and did not identify any concerns. This item is close Root Valve Left Open Due to Procedure Noncompliance On February 29, 1992, a reactor coolant system (RCS) leak occurred while operators were increasing RCS water level. The reactor was in Mode 5 (Cold Shutdown) at the time of the leak. An open instrument root valve was closed and control room operators terminated the RCS fill evolution until the root cause of the event was identified and resolve The licensee reviewed this event and determined that the RCS spill was the result of failure to use a procedure for reactor vessel level indication system (RVLIS) transmitter calibration and sensor inspection activities. Specifically, Category I procedure No. 2IC-14.3.020,

"RVLIS Transmitter Calibration, II existed for the above activities and was referenced on the associated transmitter calibration work order. However, the contractor technician assigned to the task performed the sensor inspections and began connecting the transmitter testing manifold for the transmitter calibration without using the procedure. The procedure provided a specific prerequisite to ensure that the RVLIS root valves are tagged and/or isolated.

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Operations subsequently commenced the RCS fill and vent evolution, and RCS water leaked through an open valve and to the containment floor. No personnel contaminations resulted, and there were no adverse radiological consequence The inspector reviewed this event, including the licensee's response, and determined that the licensee's followup was appropriate. A contributing factor to this event was that four separate work order activities were initiated for the three sensor inspections and tli.e one transmitter calibration. One procedure currently performs all four tasks. Additionally, the correct procedure was not referenced for the three sensor inspections. Nonetheless, the contractor technician's employment at the site was terminated by the licensee. The licensee also implemented changes to the affected work orders to ensure that recurring work orders for tasks that have been consolidated into a single procedure are appropriately planne Based on a review of numerous other related tasks during the outage, the inspector concluded that this was an isolated occurrence for which appropriate corrective action has been take This licensee-identified violation is not being cited, because the criteria specified in Section V.G of the Enforcement Policy were satisfie Engineered Safety Features (ESF) Actuation Due to Incorrect Protection Relay Installation On March 15, 1992, a control room ventilation isolation occmTed at-Unit 2. The unit was in Mode 5 (Cold Shutdown). Several minutes prior to the isolation, plant operators had attempted to start the No. 24 containment fan coil unit (CFCU). Due to an overcurrent condition upon the CFCU start attempt, the associated 230/460 volt vital bus was automatically de-energized (tripped). Control room radiation monitor No. 2R1B was powered from that electrical bus. Upon loss of the 230/460 volt bus, the recently modified uninterruptible power supply (UPS) source began to provide power to 2R1B. However, -the power supply (battery) subsequently depleted and 2R1B de-energized, resulting in the ESF actuation. The UPS was provided only to prevent short term electrical transient and spike problems and not to provide a long term backup power supply. All systems functioned properly in response to the control room isolatio Licensee investigation of this event identified that the overcurrent protection relays for the 230 and 460 buses were reversed. That reversal resulted in a premature tripping of the 230/460 volt bus during the 460 volt CFCU start attempt. The licensee subsequently reversed and tested the associated relays and inspected the protection relays on the other 230/460 volt vital buses. No additional deficiencies were identified. The licensee determined that the relays were reversed due to personnel error. Specifically, both sets of relays were previously removed for testing; however, they were reinstalled backwarqs. The relays look to be identical, although they have different setpoints..

The inspector was present in the control room when the isolation occurred and concluded that operator response to the loss of the 230/460 volt bus and the isolation was good. Abnormal operating procedures and Technical Specifications were properly used. Following the maintenance repairs and inspections, the control room ventilation system was restore9 to norma Unit 2 Startµp Preparation Surveillance Testing; Inadvertent Engineered Safety Features Actuation As part of their Unit 2 startup inspection activities, the resident inspector staff reviewed the procedures for, and performance of, various complex surveillance tests required by Technical Specifications to be performed prior to returning the unit to service. The reviewed procedures were all new procedures which had just been through the Procedure Upgrade Project (PUP) and, in some cases, were a consolidation of a number of older surveillance procedures now intended to be performed as one procedur On March 16, 1992, the Unit 2 operating crew performed procedure S2.0P-ST.SSP-0001 (Q), "Manual Safety Injection - SSPS." This procedure was performed in order to verify the ability to initiate a Safety Injection (SI) signal from the control room and tq verify all applicable plant systems and equipment actuate and properly. respond to that signal. The inspector witnessed the *performance of the test from the Unit 2 control room and, after reviewing the completion of the initial conditions check list, observed the initiation of the first SI signal called for by the procedure. The inspector noted that the operators had a difficult time performing the procedure. Specifically, although communications with field operators and supervisory command and control were good, the operators encountered unexpected plant responses, unobtainable required instrument readings, and an actual inadvertent Engineered Safety Feature (ESF) actuation. While some of the trouble encountered was due to editorial errors in the new procedure, some were also due to a lack of understanding of plant design reflected in the procedur The operating crews were observed by* the inspector to be deliberate in their performance of the procedure and in their dealings with the problems encountered. The crews halted the test numerous times to resolve discrepancies, and the procedure was revised three times before the test could be completed. Following the completion of the surveillance test, the inspector reviewed all data taken during the test and the procedure revision history with the Unit 2 Operations Engineer. The inspector determined that most of the flaws in the new procedure should have been identified in the licensee procedure review process, but the operators dealt well and properly with the procedure the first time it was performed, and all requirements of the procedure were me An inadvertent ESF actuation occurred on March 16, 1992, while the inspector was observing the licensee perform S2.0P-ST.SSP-0001(Q). While establishing conditions for an

"A" train manual SI test, the "B" train solid state protection system test/inhibit switch was manipulated. This resulted in the SI block signal being removed. At the time, a valid high

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steam flow coincident with low average coolant temperature signal was present due to new*

transmitters being installed in the steam flow channels. With those bistables tripped and the SI block removed, the "B" reactor trip breakers, an actuation of an ESF component, opene The inadvertent switch manipulation was the result of a combination of operator.error and an inappropriately placed caution statement in the procedure. The inspector observed the

response of the operators and noted the SI test was properly stopped while the trip breaker.

opening was investigated. The inspeetor concluded that the operator response was good and all reportability requirements were satisfied prior to the resumption of the manual SI tes On March 18 and March 19, 1992, the inspector observed the performance of additional complex surveillance procedures required for unit startup, S2.0P-ST.SSP-0002(Q), "ESF -

Manual Safety Injection SEC Section - 2A Vital Bus" and S2.0P-ST.SSP-0003(Q), "2B Vital Bus," respectively. These procedures were also new procedures produced by PUP and verified the operability of the safeguards equipment cabinet, the emergency diesel generators, and various safety related equipment under postulated loss of offsite power and accident conditions. The inspector observed very good control of control room access during the procedures and good communications and control of field activities. Contrary to the observations made during the initial performance of S2.0P-ST.SSP-0001(Q), these revised test procedures were performed more smoothly and had fewer technical discrepancies. *The inspector reviewed the collected data from the test and determined all requirements of the surveillance test had been: met. Procedures were amended as necessary. Ineffective Communications Resulting in Delayed Surveillance Implementation On two occasions, Technical Specification (TS) required chemistry samples were delayed or missed, primarily due to ineffective communications between operations and chemistry personnel. In both instances, the chemistry sample was required due to an inoperable radiation *monitor (RM).

On February 24, 1992, a chemistry technician misinterpreted verbal information from a

. licensed control room operator and concluded that samples previously required to be taken every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> were no longer required. In reality, the Action requirements of TS 3.3. concerning RM No. 1R13E (containment fan coil unit service water discharge monitor) still applied, and the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> grab sample and analysis was required. In this instance, however, the licensee identified the communication deficiency and completed the sample analysis about two hours lat NRC Inspection Report 50-272/91-09 reviewe4 the licensee's practke of applying the. 25%.

allowable extension interval per TS 4.0.2 to TS Action Statement grab samples.. That report

~oncluded that the licensee's practice was acceptable. Therefore, on February 24, 1992, the late sample was in compliance with TSs.

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On February 28, 1992, another communication deficiency resulted in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> grab sample

. not being taken and analyzed. RM No. lRl lA (containment particulate monitor) was declared inoperable at 3:45 a.m. Unit 1 TS 3.4.6.1 requires that grab samples be obtained and analyzed at least once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when lRl lA is inoperable. Chemistry subsequently became aware of the inoperable monitor and completed a containment sample analysis by 10:20 a.m. on *February 29, 1992, 35 minutes beyond the allowable extension of six hours. The sample did not reveal any abnormal containment radioactivity level The licensee evaluated the above two events, which included a review of the process by which chemistry personnel are notified of inoperable RMs. * The licensee subsequently instituted changes to tha~ process to enhance both operations and chemistry personnel communication.s and accountability. Additionally, the appropriate individuals involved were counseled. The inspector reviewed the licensee's corrective a,ctions and concluded that they were acceptabl *

The February 28, 1992 missed surveillance constitutes a violation of TS 3.4.6.1. However, this matter had minor safety significance and was corrected by the licensee, including actions to prevent recurrence. This licensee-identified violation is not being cited because the criteria specified in Section V.G ofthe Enforcement Policy were satisfie Missed Technical Specification*Surveillance On March 13, 1992, the licensee discovered that a Technical Specification (TS)_ suryeillance on a Unit 1 steam generator blowdown flow transmitter had been overdue since July 4, 199 The task had been misCiassified as a preventive maintenance (PM) task, *rather than a surveillance task (ST), and was therefore permitted to be deferre *

The licensee tracks PMs and STs in a recurring task (RT) report, which maintains an active copy and a library copy. The library copy is a permanent record of surveillance due dates, from which a short-term active copy is generated. STs on the active copy appear on a "14-

. day look-ahead" report as they approach their overdue dates. PMs, unlike STs, are permitted to be deferred due to higher priority work and do not appear on the "14-day look ahead" report. The* loop 2 steam generator blowdown flow transmitter ST was misclassified as a PM tasks on the active copy and was thus omitted from the "14-day look-ahead" repor The missed surveillance was successfully completed _immediately upon discovery of the omission. When the licensee checked the classification of the same tasks for the other three loops, loops 3 and 4 were also found to be incorrectly classified on the active copy. The past surveillances~ for loops 3 and 4 were not def erred, however; they were completed in time to fulfill the TS requirements. The loop 1 surveillance was correctly classified. In addition, all of these tasks were correctly classified on the library copy of the RT report.

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This issue is being resolved by the licensee. The licensee completed a TS audit in 1990, although only the library copy of the RT report was audited. A program was previously written to identify and correct. ~y variations between the active copy and the library copy; but task coding was not one of the parameters used. By Maren 30, 1992, this program will'

be upgraded by the licensee to check all of the tasks on the active copy for proper task coding as wel The inspector concluded that the licensee took appropriate corrective actions to ensure the proper tracking of TS Surveillance Requirements~ This licensee-identified violation is not being cited, because the criteria specified in Section V.G of the Enforcement Policy were satisfie.3.2 Hope Creek Maintenance/Surveillance Support of March 1992 Mini-Outage Hope Creek was shut down on March 7, 1992, for a mini-maintenance outage.in order to prepare the plant for the summer peak electrical generation demand. The outage schedule included the following major work

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replacing the "A 11 reactor recirculation pump No. 2 seal, replacing piping and valves in the "B 11 loop of the station service water system, repairing v~ve stem packing leaks in the main steam tunnel, conducting emergency diesel generator corrective maintenance and inspections, and implementing a design change to the startup logic of the "E" and "F" filtration, recirculation and ventilation system (FRVS) fan~.

Additionally, some*3Q% emergent work was also performed., Despite this unplanned work, ess_entially all of tpe scheduled activities were successfully completed with no rework...

The inspector observed selected field activities and discussed the planning and scheduling efforts with outage management. The inspector noted the efforts made to keep all personnel aware of equipment status and to assure an understanding of the schedule and reasons for adhering to it. Especially noteworthy were the measures taken to reduce the period of vulnerability for reliable decay heat removal capability while the 11B" service water loop was out of service. For example, the licensee identified the critical activity of the se~ice water *

• work (replacement of the 11B" and 11D 11 pump discharge valves), scheduled the work up front and prepared special procedures to permit a rapid return to service should that loop be * *

required. Briefings were held with the craft and line supervision stressing the importance of their work and the potential effects on the plant. These and other measures reduced the vulnerable period from about 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> to around 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

Throughout the outage, the inspector noted the close cooperation that existed between all affected groups. The station quality assurance (SQA) department provided 24-hout shift coverage, and performed a number of surveillances and about 650 hold point. inspections~

The inspector did not note any significant impact on scheduled ot emergent wo~k *

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performance due to a lack of spare or replacement parts. Close management attention was also evident in both the planning and execution of the outag *

In summary, the inspector concluded that the mini-outage was well planned with reactor safety being the top priority. Overall work performance and q~ality was very good and the outage's success was due in large part to the cooperative efforts of all involved. * EMERGENCY PREPAREDNESS Inspection Activity

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The inspector reviewed PSE&G's conformance with *lOCF~0.47 regarding implementation of the emergency plan and procedures. In addition, licensee event notifications. and reporting requirements per 10CFR50. 72 and 73 were reviewe.2 Inspection Findings Unusual Event Due to Transport of Contaminated Injured Individual On February 29, 1992, Salem declared an Unusual Event after a contractor employee fell about ten feet while attempting to exit the lower reactor cavity. The individual fell from the top of the lower cavity ladder, cutting the back of his head. He was transported to a local hospital for treatment. Since the individual was contaminated as determined by radiation protection personnel, an Unusual Event was declared at 3:20 p.m. in accordance with the licensee's Emergency Classification Guide (Section 15.A). The Unusual Event was terminated at 5:05 p. ril. after the individual was decontaminated. The inspector reviewed th licensee's response and emergency declaration for the medical *emergency and did not identify any deficiencie Unusual Event (UE) Declared Due to Emergency Core Cooling System (ECCS)

Initiation and Vessel Injection *

At 5:32 p.m. on March 8, 1992, the licensee declared an UE when a spurious "B" channel ECCS initiation signal started the "B" emergency diesel generator (EDG), and both the "B" core spray and "B" residual heat removal pumps and injected to the reactor vessel (see Section 2.2.2.A of this report for details). The event was properly cl~ssified and all required notifications were made in a timely manner. The residual inspector was informed at hom After stopping the injection and resetting the initiation logic the UE was terminated at 5:36 p.m.

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SECURITY Inspection Activity PSE&G' s conformance \\\\'.ith the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries. These inspection activities were conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings The inspectors determined that security program implementation was appropriat.

ENGINEERING/TECHNICAL SUPPORT Salem Open Item Followup (Closed) Unresolved Item 50-272/89-27-01. Review of operating experience and vendor

. recommendation programs. The licensee reviewed their programs and implemented procedural and programmatic enhancements, which included the establishment of a single group to administer the vendor information control program. Additionally, correspondence was submitted to vendors to solicit support in improving PSE&G's internal control of technical information. A memorandum was also issued to all nuclear department personnel*

regarding responsibilities for vendor technical information processing. The inspector concluded that appropri_ate measures have been taken to address the previously identified weaknesses; This item is close *

(Closed) Unresolved Item 50-272/90-04-01. Cable separation deficiencies associated with temporary extension cords and telecommunication cables. * In response to the concerns, the licensee issued a memorandl,lm to all field personnel concerning the proper use of extension cords relative to cable separation. Additionally, a Technical Standard was developed, N ND.DE-TS.ZZ-200l(Q), "Telecommu.nication _Cable Installation and Removal," to establish specific design and routing requirements for telecommunication cabling for both the Salem and Hope Creek facilities. The inspector reviewed the licensee's actions and performed a walkdown of specific plant areas. No deficiencies were identified, and this item is close (Closed) Unresolved Item 50-272/90-24-01. Improper setpoint for two Unit 1 containment fan coil unit radiation monitors. The inspector reviewed the licensee event report associated with this event, and concluded that the licensee's response and corrective actions for this event were appropriate. No additional concerns were identified. This item is closed.

21 Mairi Steam Line Radiation Monitors Determined to be Inoperable Each Salem unit has five main steam line radiation monitors, R46, A through E. Monitors A

. through D are on the individual steam lines, and the R46E channel is downstream of the common discharge header of the other four R46 monitors. On January 28, 1992,

Instrumentation and Control (l&C) technicians performing channel calibrations rioted that the detectors in some of the Unit 1 and Unit 2 R46 monitors were not the ones required. The affected channels were 1R46 A, C, and D, and 2R46 A, B, C, and E. At the time of the discovery, Unit 1 was operating at 100% power, and Unit 2 was shut down for refueling, with the reactor defuele Salem Technical' Specifications (TS) requires one R46 per main steam line to be operable in

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Modes 1 through 4, therefore only Unit 1 was placed in a TS Action to initiate a preplanned alternate method of monitoring within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and to restore the inoperable channels to an operable status within seven days. The affected channels were declared inoperable~because

. the incorrect detectors were not properly environmentally qualified Class IE. In order to comply with the TS, PSE&G replaced the 1R46 A, C, and D detectors with the good detectors from the 1R46E and 2R46D channels and with one of the incorrect detectors which was converted by the vendor to be a qualified detector. The licensee initiated plans to have

.the 1R46E and all Unit 2 R46 detectors replaced with Class lE.deteetors prior to restart of Unit.

When informed that a number of R46 channels had been declared inoperable, the inspector confirmed that the operating crew had entered the proper TS Action Statement and verified with the Salem Chemistry Department that an alternate method of steam line monitoring was available.. Subsequently, PSE&G determined and informed the resident inspector that the *

cause of the unqualified detectors being installed was an incorrect classification of the part as non-Class lE when the R46 channels were installed per a design change in 1983. As the originally qualified detectors were replaced following initial installation, they were replaced with the incorrect part. By the end of the report period, the inspector had verified that the required Unit 1 R46 detectors were ones which met the required Class IE criteria, that the PSE&G parts folio system had been modified to require Class lE detectors for the R46 monitors, and that work orders had been developed to replace the 1R46E and all Unit 2 R46 detectors with the proper detector prior to Unit 2 restar The Inspector determined that, although these detectors were never environmentally challenged, having non-IE detectors installed may have prevented the R46 monitors from performing under certain accident conditions. The R46 channels only provide an alarm function (i.e. no interlocking function). Additionally, other radiation monitors exist on related systems (steam generator blowdown, condenser air ejector) to corroborate the R46 indications. Once the deficiency was identified, the inspector concluded that PSE&G did a good and timely job in restoring Unit 1 R46s to an operable status and making provisions to correct Unit 2 pnor to that unit's return to service.

22 Hope Creek High Pressure Coolant bijection (HPCn System Licensed operators placed the HPCI system in a standby mode Qf operation during unit startup and reactor pressurization on March 15, 1992. The emergency core cooling system (ECCS) Technical Specification (TS) 3.5.1.C requires HPCI operability in Operational Conditions 1, 2 and 3 when reactor pressure is greater than 200 psi On the afternoon of March 16, 1992, with the reactor critical and reactor pressure at about 400 psig, the inspector noted that the HPCI was correctly aligned for a normal standby mode. However, the HPCI turbine trip annunciator was alarmed, and a high reactor water level (level 8) trip was actuated. The inspector questioned control room operators concerning the status of the HPCI system. The operators stated that HPCI was operable, however, a high level trip was actuated because the wide range reactor water level instrumentation was indicating falsely high (greater than the +54 inches trip setpoint).

Actual reactor water level was normal at + 35 inches. The operators further stated that this condition was due to the fact that the reactor wide range level instrument was calibrated hot (e.g., at normal reactor pressure of 1000 psig). The in-spector noted that the wide range level instrument was on scale, indicating about +60 inches. Within a few minutes the operators were able to reset the high level HPCI trip when indicated level decreased to less than +54 inche The inspector questioned HPCI system operability as required by TS 3.5.1.C and by the ECCS actuation instrumentation (TS Table 3.3.3-1 items 3a and 3b). The HPCI system is required to actuate on both low-low reactor water level (level 2) and high drywell pressur Operators stated that if reactor level were to decrease, the high level trip would automatically reset, and HPCI would actuate and inject when the low-low reactor water level setpoint was reached. The inspector verified this through discussions with system engineering and operations personnel and by reviewing system electrical schematic drawings. However, it appears that HPCI would not automatically actuate on high drywell pressure as l~ng as reactor level remained above the high level HPCI trip setpoint under this low reactor pressure conditio The inspector also reviewed related alarm response, system operating and integrated operating procedures. The inspector could not find any step in these related procedures that directed operators to reset the high level trip nor any guidance regarding this HPCI issu The inspector discussed this item with plant management, the NRR project manager, and NRR technical specialists. At the end of the inspection period, licensee personnel were pursuing this matter. Apparently a design change during initial startup (1985) modified the reactor water high level trip bypass logic. This issue of HPCI automatic initiation for high drywell pressure at low reactor pressures, including TS adequacy and procedural guidance, is unresolved pending licensee review and subsequent NRC followup (UNR 50-354/92-02-01).

23 Filtration, Recirculation and Ventilation System (FRVS) Fan Automatic Start On February 16, i992, the- "E" FRVS reeirculation fan automatically started. The fan was stopped after about ten minutes of run time after operators determined that the initiation was spurious. While FRVS fans had been run the previous day, the low flow switch instrument lines had been drained, per procedure, following that run. No water had been fourtd at that time. However, engineering personnel indicated that because of the small diameter of the sensing lines it was extremely difficult to be sure all water had been drained. Following their investigation, the licensee concluded that the root cause of the spurious start was most likely due to moisture in the sensing lines which had been the cause of numerous starts _of*

• both the "E" and "F" FRVS fans for some time. The inspector reviewed the event with licensee engineering and operations personnel and concluded that the licensee's determination was reasonabl *

In Licensee Event Report (LER) No. 50-354/91-19, the licensee had committed to implementing a design change to address the spurious start of the "E" and "F" FRVS fan Due to the scram risk involved, implementation was deferred until the next scheduled outag During the short outage in March 1992, design change DCP 4EC-3226 was installed and tested satisfactorily. The logic circuitry 'was altered to include a short time delay (approximately two seconds) in the low suction flow switch signal to screen out spikes aild to require the presence of a valid initiation signal (high di"ywell pressure or refuel floor radiation) before either fan would start. The inspector reviewed the design change documentation and associated safety evaluation and discussed the change with licensee engineering and maJ).agement personnel, concluding that the Safety aspects of the modification had been appropriately addressed. At the time, the licensee also indicated that investigation into the source of the moisture and consequent corrective actions were being actively pursued. Final resolution of these issues would be reported in a revision to LER 91-1.

SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Open Item Followup (Closed) Unresolved Item 50-272/90-81-06. Insufficient verification. of Technica Specification (TS) 4.S-.1.1.2.b and TS 4.8.1.1.2.c.7 in the emergency diesel generator (EDG)

surveillance test procedures. Procedures SP(0)4.8.1.1.2.c. 7.A/B/C, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> EDG surveillance procedures, did not address TS 4.8.1.1.2.b, which requires that "at least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to. one hour, check for and remove accumulated water from the day tanks."

The procedure also did not adequately address TS 4.8.1.1.2.c.7, which requires that steady state voltage and frequency shall be maintained at specified values. Procedures

SP(0)4.8.1.1.2.c. 7.A/B/C have been modified by the Salem Procedure Upgrade Projec The inspector verified that the new procedures adequately address the noted TS requirement This item is close (Closed) Unresolved Item 50-272/90-81:-07. Inadequate incorporation of acceptance criteria in EDG surveillance test procedures SP(0)4.3.2.1.(A)4 and SP(0)4.8.1.1.2.c. 7.A/B/ Both of these procedures have been revised as part.of the Salem Procedure Upgrade Projec The inspector verified that the new procedures contain separate sections which clearly define acceptance criteria for the test. Based on the above, this item is close (Closed) Unresolved Item 50-272/90-81-08. Potential misapplication of procedure review process for diesel generator surveillance procedure. This item was another example of an inappropriate safety significant issue (SSI) determination, for which a Notice of Violation

• was issued in NRC Inspection Report 50-272/90-22. -Based on the subsequent elimination of the use of SSI determinations and subsequent programmatic resolution of this issue, as documented in 50:..272/90-22, this item is close (Closed) Unresolved Item 50-272/90-200-02. * The threshold for identification and escalation of deficiencies to one of the formal systems was too high, resulting in a high probability that significant problems could exist for long periods of time before licensee management would learn of and correct the problems. The inspector reviewed the licensee's Nuclear Administrative Procedure (NAP) 6, "Incident Report/Reportable Event Program and Quality/Safety Concerns Reporting System," and determined that measures have been established to assure that conditions adverse to quality are promptly i4entified and correcte A review of recent station events and the associated issuance of incident reports indi~ate that NAP-6 is being effectively implemented. This item is close (Closed) Unresolved Item 50-272&311/92-01-02. The Unit 2 reactor coolant pump (RCP).

seal return relief valve (No. 2CV115) was found to have an unauthorized gagging device installe Th~ licensee subsequently committed to perform a su_rveillance of selected relief valves to verify that none were gagged or damaged. A surveillarice was completed by the licensee, which. documented the successful inspection of a significant number of safety valves. The inspector reviewed the associated surveillance report and did not identify any deficiencies. This item is close Inadequate Licensee Event Report; Open Item Followup (Open) Unresolved Item 50-272/91-05-02. Resolution of potential accident mitigation deficiency (missing/degraded seismic gap high energy line break seals). NRC Inspection Report 50-272/91-05 documented this event and the NRC review of the *associated Licensee Event Report (LER) No. 91-09, dated March 15, 1991. That inspection report noted that the licensee had not completed an evaluation to determine whether safety related equipment would have remained operable under accident conditions and the safety impact of the as-found conditio.

On January 30, 1992, the licensee submitted a supplemental LER to address the above concerns. An engineering analysis had been completed to support the LER supplement on September 27, 199L That LER stated that the results of a probabilistic risk assessment (PRA) evaluation showed a significant increase in the core damage frequency: The supplemental LER also stated that because of a lack of supporting test data~ operability of safety-related electrical equipment could not be demonstrated. As a result, the room coolers for safety-related pumps would have become inoperable, and consequently, the associated safety-related pumps would have become inoperable.. Those pumps include the auxiliary feedwater, charging, safety injection, residual heat removal,' containment spray, and component c~oli_ng water pump The LER, however, did not consider other factors which would minimize the safety impact of the event. SpeCifically, the LER supplement did not identify that even with the loss of the room *coolers, the pumps would actually operate for some time period, and that the pump areas are supported by a Class IE normal ventilation unit. Therefore, with those factors considered, accident mitigation could apparently have been accomplished under the assumed accident condition *

The inspector reviewed the supplemental LER and the supporting engineering evaluation and identified the following:* the engineering evaluation was not complete in* that it did not

. _positively demonstrate whether equipment was operable under the accident sequence involved. Therefore, all safety-related pumps were. assumed to be inoperable. The supplemental LER included incorrect PRA core damage frequency numbers and incorrectly concluded that a significant increase in core damage frequency resulted; Additionally, the supplemental LER failed to properly address the safety impact of the even The inspector discussed these concerns with the licensee, who stated that a further review preliminarily shows that the assumed accident may have been mitigated, contrary to the supplemental LER conclusions. At the end of the inspection period, the licensee was completing additional reviews and plans to resubmit a supplemental LER. This item remains unresolved pending completion of the additional reviews and resubmittal of a. supplemental*

LE Diesel Generator Operability in Modes 5 and 6 During a review of the Salem Technical Specifications (TSs), the inspector identified ah apparent inconsistency in the diesel *generator TSs for Units 1 and 2. The surveillance requirements for A.C. electrical power sources for a shut down unit (Modes 5 and 6) are delineated in TS 4.8.1.2. These surveillance requirements identify what is neeessary to demonstrate the operability of the electrical power sources. Two such sources, two diesel generators, are among the required operable power sources. TS 4.8.1.2 references portions of the TS surveillance requirements on A.C. sources for an operating unit (Modes 1 through 4). Among these referenced requirements is a verification that the diesel generator starts on the auto-start signal and *energizes the auto-connected shutdown loads through a sequence *

The safeguards equipment cabinet (SEC) is the functional unit that automatically starts and*

• loads an associated diesel generator. Therefore, in order to satisfy the diesel* generator operability requirements, the associated SECs, in addition to the diesel generators, must be.

energized and operable. The SEC, however, is required by TS 3.3.2 only to be operable in Modes 1 through *

The licensee's current standard practice is to maintain an operable SEC for an associated operable diesel generator train, although one instance was found by the inspector at Unit 2 in *

which the diesel generator was declared operable without an energized SEC on that same train. A further review of that instance identified that the associated TS Action requirement was followed (i.e. no core alternations or positive reactivity insertions were made). The inspector also confirmed that an Abnormal Operating Procedure (AOP) was in place which guides operators through the manual start of a diesel generator upon loss of A.C. coriditions while shutdow The inspector discussed this concern with licensee and NRC Headquarters personnel, and concluded that when the reactor is in Modes 5 or 6, assoCiated SECs must be operable 'for operable diesel generators. The licen.see has several measures in place to resolve this issue and is considering a TS amendment to clarify the role of the SEC in diesel generator operability. The inspector concluded that this issue did not represent a safety concern; however,* the licensee's efforts should continue toward resolution of the apparent*

inconsistency among related TS requirement.2 Hope Creek Temporary Instruction (Tn 2515/113 - Reliable Decay Heat Removal During Outages Overview TI 2515/113 addresses the practices used by licensees to ensure that plant configurations and.

operations during outages maintain a continuous decay heat removal (RHR) capability. Prior to and during a scheduled mini-mainte.nance outage conducted from March 7, 1992 to.March 17, 1992, the inspector reviewed the licensee's p91icies and procedures governing outage planning, scheduling and control of work activities as they related to shutdown cooling capability. Management personnel were interviewed to ascertain their perspective on shutdown risk management, including operator training dealing with shutdown events, review of previous events at other power reactor facilities, and nuclear industry initiative Program Description The licensee has in place a department procedure, NC.NA-AP.ZZ-0055(Q), "Outage Management Program" (NAP-55), which provide guidelines and administrative controls for both forced and scheduled outage activities. NAP-55 scope includes management

organization and responsibilities, schedules and implementing requirements, meetings, goals

_ and reporting requirements. Section 3 of NAP-55 delineates the specific responsibilities of personnel involved with any phase of an outage. The outage manager, who reports directly to the pfant's general manager, is tasked with ensuring that the plant safety philosophies are reflected in outage planning and scheduling. Specific guidelines for the utilization of risk-management outage planning concepts are contained in Section 5.3.1 of NAP-55. During

. schedule preparation, an assessment is required evaluating planned outage activities again.st a number of shutdown safety is.sues:

decay heat removal capability* *

outage inventory control

electrical power availability,and reliability

reactivity control *

_

primary and secondary containment integrity Following the development. of the outage schedule, the on-site Safety Review Group (SRG)

will perform an independent review of the schedule which assesses:

The outage schedule, including system interactions, support system availability, and the impact of temporarily installed equipmen *

The adequacy of the Defense In Depth provided for each phase of the outage.

That higher risk evolutions are clearly identified in the schedule and that appropriate contingency plans have been develope *

Compliance with the guidelines of NAP-55 and the Nuclear Management.and Resources Council (NUMARC) and Institute of Nuclear Power Operations (INPO)

guidance for the safe conduct of outage Emergent work requiring schedule change is reviewed against the same criteria prior to a change being implemented. As necessary, a contingency schedule would be developed to account for anticipated failures of high risk aciivities. Such a schedule would also be reviewed by the on-site SRG to the criteria noted abov NRC Findings/Observations

NAP-55. refers to SRG review only for refueling outages. The licensee indicated, however, that such a review was intended for other types of outages as well.

Licensed operators received specific training in shutdown operations on the plant simulator prior to an outage, focusing on a loss of shutdown cooling, reactor building integrity and inadvertent criticality potential. Specific operating procedures (abnormals, or ABs) were in place addressing a number of potential events while shutdown, inducting a loss of shutdown cooling or containment integrity:

Revision 0 of NAP-55 contained many of the guidelines for assessing shutdown risk managemenUisted in NUMARC 91:.06, issued December 1991. The licensee indicated that full implementation of the NUMARC guidelines will be complete about three months prior to the next refueling outage (currently scheduled for September 1992).

• As an aid to all personnel involved with the outage, a list of equipment, iricluding electrical power supplies, required to be operable to provide for nuclear safety and integrity, was made available at each shift turnover. The licensee stated that this was an initiative based on industry experience. While some refinement was needed, licensee personnel appeared favorable to its use. The inspector noted the lists posted in many work and planning area *

The licensee used a test manager concept in controlling safety significant plant equipment and support systems during times when plant vulnerability tb shutdown risks was greater than normal. The manager was responsible for verifying that stated prerequisites for an evolution were met and monitored until the window of

-

vulnerability was close Because of limited regulatory requirements in this area, the inspector did not asse*ss the adequacy of the program discussed above. Licensee activities during the nine day March 1992 maintenance *outage are reviewed in other sections of this inspection repor.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP 9.1 LERs and Reports PSE&G submitted the following licensee event reports and special and periodic reports, which were reviewed for accuracy and evaluation adequacy. These reports were-reviewed in accordance with NRC inspection procedures 90712 and 9071 *

Salem LERs Unit 1

. *

-LER 92'-01 reported similar engineered safety feature (ESF) actuations, where on two

occasions, the No. 12 steam generator (SG) blowdown outlet isolation valve (a

containment isolation valve) failed closed. On January 7, 1992, the air-operated valve's diaphragm ruptured and the valve failed to its fail-safe position (closed). A contributing factor to the failure was premature aging of the diaphragm due to a

• localized heat source. The heat source was SG blowdown piping whose insulation was previously removed during maintenance but not reinstalled. The diaphragm was replaced, and the insulation was reinstalle On January 28, 1992, the same valve again failed closed due to a ruptured diaphrag That diaphragm was found to be torn in the same location; however, the failure.did not appear *to be due to preventive aging (diaphragm was resilient). The diaphragm was replaced and the valve was successfully tested on January 29, 1992~

The LER noted that a failure analysis of the January 28, 1992 diaphragm failure had been initiated and that system engineering was continuing an assessment of the cause(s) of the valve failures. However, the LER does riot state that a supplemental LER would be provided. Th~ inspector brought this to the licensee's attention, who subsequently stated that a supplemental LER would be provided following completion.

of the above evaluatio *

LER 92-03 reported an automatic control room ventilation isolation (ESF actuation)

due to a high channel spike on control room ventilation monitor lRlB. *This event was due to a broken detector shield wire solenoid connection and was reviewed as documented in NRC Inspection Report 50-272/92-01. No deficiencies were noted relative to this LE LER 92-04 detailed the licensee's findings of iricorrect detectors being installed in both the Unit 1 and Unit 2 R46 radiation monitoring system* channels. This event is discussed in Section 7. LB of this report, and no inadequacies were noted relative to the LE LER 92-05 concerned ESF actuations as a result of an inadvertent trip of a 120 volt AC breaker which provided electrical power to several radiation monitors. Upon the loss of specific radiation monitors (lRlA and lRllA), both the control room ventilation and containment purge/pressure - vacuum relief systems isolated. This event was reviewed as documented in NRC Inspection Report 50-272/92-01. No inadequacies were identified relative tO this LER.

-.

Unit 2

LER 92-01 _concerned an ESF actuation (diesel generator automatic start) when the

. No. 2A 4l}v vital bus experienced an undervoltage condition due to an equipment.

failure. This event was discussed in NRC Inspection Report 50-311192-01. No LER deficiencies were identifie LER 92-02 documented a condition identified by the licensee in which an electrical penetration circuit was not protected by a* secondary device. That conductor could have potentially damaged the electrical penetration in the event of an overcurrent fault and the coincidental failure of the primary device. The cause of the event was a personnel error in the design change process, whereby incorrect iriform'ation was.

derived froin the wiring diagram to develop schematic drawings and the secondary device was not installed during the design change. Only one penetration circuit was involved, and the licensee verified that a similar condition did not exist with other Unit 1 and 2 penetrations. No inadequacies were identified relative to this LE LER 92-03 concerned three separate ESP actuation signals for control room ventilation isolation that occurred on January 23, 1992. The root cause of the isolations was system design inadequacy, and these events are indicative of the known radiation monitoring system design deficiencies fo:r: which modifications are currently being implemented. These events were also reviewed in NRC Inspection Report 50- * * *

311/92-01. No.inadequacies were not~ relative to this LE Hope Creek LERs

LER 91-20 described -a December 7, 1991 inadvertent isolation of the High Pressure Coolant Injection (HPCI) system due to the mis-wiring of the control module for the 11A 11 channel isolation circuitry. The safety significance of this event was minimal.

. Licensee's corrective actions included rewiring the thermocouple field junction and inspecting the other circuits for a similar problem (none were found). The LER was well written and no discrepancies were note *

LER 91-19-0r and 91-19-02. These two revisions to LER 91-19 detail additional spurious autorhatic starts of the 11B" and 11F 11 filtration, recirculation and ventilation system (FRVS) fans. For details, see NRC Inspection Reports 50-354/91-19, 91-21 and 92-01. The inspector noted that the design change to the fan start logic had 'been implemented during the March 1992 outage. Additionally, the licensee committed to submitting a follow-up report after determining whey water accumulated in the instrument lines. No discrepancies were noted in this LER.

')

31-LER 92-01 discussed a trip of the "A" reactor protection system (RPD) motor generator set electrical protection assembly (EPA) breakers dueto personnel error (See NRC Inspection Report 50-354/92-01, Sec;tion 4.3~2 for details). No

• discrepancies were noted in this LE *

LER 92-02 dealt with a Technical Speeification (TS) 3.0.3 entry due to both trains of

• control room ventilation being inoperable~ (See NRC Inspection Report 50-354/91-02, Section 2.2.2.B, for details.) The inspector noted that the licensee's

'

correctiveactions appeared to thoroughly address the engineering and operational issues involving control room ventilation performance. The LER was weli-written and accurat *

LER 92-03 discussed an engineered safety feature actuation when the "A" control room emergency filtration system automatically started after a ventilation radiation detector failed upscale. Investigation revealed that the foil shield had failed and light had impinged on the detector when test sources were introduced into the ductwork while testing a companion detector. The failed detector was undergoing analysis.

. There were no significant deficiencies noted in. this LE Periodic and Special Reports

Salem and Hope Creek Semi-Annual Fitness For Duty Performance Data for the six

. month period ending December 31, 199 *

Salem and Hope Creek Monthly Operating Reports for January and February, 199 *

Salem and Hope Creek Semi-Annual Effluent Release Reports for the period July 1 -

December 31, 199 *

Salem and H~pe Creek Annual Radiation Exposure Report for 199 *

Hope Creek Annual Report - Technical Specification 6.9.1.5, which addressed challenges io main steam line safety/relief valves for the year 199 *

• Hope Creek Special Report 91-04, which addressed the south plant vent high range noble gas monitors being inoperable for greater tha:n 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> *

Salem Special Report 92-01, which addressed a fire barrier impairment which had not been restored to a functional status within seven day No unacceptable conditions were noted relative to these reports.

'1

9.2 Open Items The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose Salem 1 & 2 50-272/90-19-03 50-272/90-81-03 50-272/90-200-04 50-311/90-04-01 50-272/89-27-01 5 0-272/90-04-01 50-272/90-24-01 50-272/90-81-06 50-272/90-81-07 50-272/90-81-08 50-272/90-200-02 50-272&311/92-01-02 50-272/91-05-02 Hope Creek None Report Section 2.2..3..3..3.....1.A.

8......

EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting Closed Closed-Closed. *

Closed Closed Closed Closed Closed Closed Closed Closed

. Closed Open The inspectors met with Mr. C. Vondra and Mr. J. Hagan and other PSE&G personnel periodically and at the end of the insp~tion report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report. does not contain iriformation subject to 10 CPR 2 restrictions.

1 Specialist Entrance and Exit Meetings Date(s) *

2/18-21/92 3/5/92 Inspection Subject Report N Emergency Operating 50-272&311192-02

.Procedures - Open Item Followup Physical Inspection of NI A Unit 2 Damaged Turbine Components 1 Management Meetings Reporting Inspector Silk Wichman NRC Region I Administrator Thomas T. Martin toured the Salem and Hope Creek stations on March 9, 1992. Mr. Martin also met with PSE&G management personnel during the station tour B.

A meeting was held at the NRC Headquarters office in Rockville, MD on Marcq 18, 1992, to discuss Integrated Schedules. A meeting summary will be forwarded under a separate correspondence.