IR 05000272/1993001
| ML18096B288 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 02/17/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18096B287 | List: |
| References | |
| 50-272-93-01, 50-272-93-1, 50-311-93-01, 50-311-93-1, 50-354-93-01, 50-354-93-1, NUDOCS 9302240117 | |
| Download: ML18096B288 (29) | |
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No /93-01 50-311/93-01 50-354/93-01 License Nos. DPR-70 DPR-75 NPF-57 Licensee:
Facilities:
Dates:
Inspectors:
Approved:
Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station January 3, 1993 - February 6, 1993 Inspection Summary:
This inspection report documents inspections conducted to assure public health and safety during day and backshift hours *of station activities, including: operations, radiological controls, maintenanc~ and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. Findings and conclusions are summarized in the Executive Summary.
9302240117 930217 PDR ADOCK 05000272 G
EXECUTIVE SUMMARY Salem Inspection Reports 50-272/93-01; 50-311/93-01 Hope Creek Inspection Report 50-354/93-01 January 3, 1993 - February 6, 1993 OPERA TIO NS (Modules 71707, 93702)
Salem: The Salem units were operated in a safe manner. Operators appropriately initiated two manual reactor trips (one on each unit) duri'fig-the period. Operator response to these reactor trips was very good, including command and control, and emergency operating procedure implementation. Safety system response was as expected. The licensee appropriately implemented and responded to several Technical Specification 3.0.3 entries for Unit 1 rod position indication and boric acid storage tank level indicator problems. A Unit 1 load reduction due to condenser and feedwater problems was appropriate. Initial licensee *
actions for several inoperable control room instrument recorders (non-Technical Specification instruments) was incomplete; however, subsequent efforts were aggressive and effectiv Hope Creek: The unit was operated in a safe manner. The licensee appropriately addressed an open item concerning the torus hardened plant ven RADIOWGICAL CONTROLS (Modules 71707, 93702)
Salem: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirement During a tour of the Unit 1 containment, the inspectors observed the implementation of very good radiological controls and good containment housekeeping and material condition. The licensee is appropriately addressing elevated Unit 1 containment particulate radiation and monitor indications. The licensee acted conservatively and appropriately in addressing a small primary-to-secondary leak in the No. 24 steam generator in Unit Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirements. The licensee is aggressively pursuing reactor water chemistry improvements by implementing depleted zinc and hydrogen gas injections into the feedwater system.
ii
MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
Salem: The licensee appropriately initiated leak repair activities for a Unit 1 pressurizer spray valve and a reactor head vent flange leak. Maintenance department troubleshooting for a Unit 2 reactor trip due to a steam generator feedwater control system momentary failure was thorough and well planne Hope Creek: The licensee demonstrated comprehensive and effective followup for a failed reactor core isolation cooling system motor operated valve. The licensee appropriately addressed an open item concerning instrumentation and control technicians' valve manipulation EMERGENCY PREPAREDNESS (Modules 71707, 93702)
The licensee resolved an open item regarding 10CFR50.54x deviation SECURITY (Modules 71707, 93702)
The inspectors determined the security program requirements were appropriately me *
ENGINEERING/TECHNICAL SUPPORT (Module 71707)
Salem: Licensee system engineering personnel appropriately implemented and responded to two Technical Specification 3.0.3 entries concerning boric acid storage tank level indicator An error (both personnel and procedural) associated with a Unit 1 reactor startup estimated critical position is unresolved. Weaknesses were identified during licensee troubleshooting activities for the 2C emergency diesel generator (EDG), which resulted in an EDG overspeed trip. The issue is unresolved. The licensee appropriately addressed open items concerning auxiliary feedwater flow and main steam line radiation monitor Hope Creek: The licensee appropriately made a lOCFR Part 21 report regarding the emergency diesel generator fuel oil pump. A previous unresolved item and this Part 21 report were closed. An open item regarding transformer oil trending remains open.
lll J
SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 40500, 90713, 92700, 92701, 94600)
Salem: Licensee activities conducted in preparation for the next two refueling outages are progressing well. Line management, station operations review committee and independent event review of two reactor trips were determined to be thorough and well performed. The inspectors determined that a revised shift rotation schedule has not adversely affected control room or operator performanc Hope Creek: The licensee appropriately addressed an open item regarding a higher than expected personnel error rate during the fourth refueling outag Common: The licensee appropriately addressed open items for nuclear servic~s department controls for contractor personnel and the cross training of Salem/Hope Creek workers.
IV
SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 began the period at power. On January 16, 1993, during a planned unit shutdown, operators effected a manual reactor trip when the steam dump system failed. The unit restarted on January 21, 1993, and remained at power during the remainder of the perio Unit 2 began the period at power. On January 28, 1993, operators effected a manual reactor trip while operating at 100% when both steam generator feed pumps were inadvertently tripped during troubleshooting activities. The unit restarted on January 31, 1993, and remained at power during the remainder of the perio.2 Hope Creek The unit operated at power during the entire inspection perio.3 Common Thomas T. Martin, NRC Region I Regional Administrator, visited Artificial Island on January 7, 1993. He toured the Salem and Hope Creek facilities, the new on-site warehouse, and met with PSE&G plant and senior management personne.
OPERATIONS 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. The inspectors performed normal and back-shift inspections, including deep back-shift (13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />) inspection.2 Inspection Findings and Significant Plant Events 2.2.1 Salem Unit 1 Inoperable Rod Position Indication; Technical Specification 3.0.3 Entry On January 11, 1993, the licensee initiated two planned entries into Technical Specification (TS) 3.0.3 for one minute and two minutes, respectively. The analog rod position indication
(ARPI) display had been recently declared inoperable for control rod No. 2D4 (on January 10). TS 3.1.3.2.1 allows a maximum of one ARPI display per control rod bank to be inoperable. Actual control rod position was periodically verified in accordance with the requirements of TSs. In order to systematically troubleshoot the indication problem and to minimize the likelihood of adversely affecting other portions of the ARPI system during the troubleshooting activities, technicians momentarily pulled the fuses for the ARPI syste That action rendered greater than one ARPI display per control rod bank inoperable for a total of three minutes, requiring two separate entries into TS 3.0.3. Through discussions with the personnel involved and by reviewing relevant documentation, the inspector concluded that the two TS 3.0.3 entries were adequately planned and executed. The licensee plans to submit a Licensee Event Report for this.activity. The 2D4 ARPI was subsequently repaired (See Sections 2.2.1.C and 4.3.1.A of this report), and TS 3.1.3.2.1 was properly exite Unit 1 Load Reduction On January 14, 1992, Unit 1 operators manually initiated a unit load reduction to 6,5% power due to an elevated temperature differential across the main condenser cooling medium. The unit was operating at 98% power prior to the load reduction. The load reduction was in accordance with station procedures in order to isolate and clean condenser waterboxe Fouling of the main condenser waterboxes results in elevated differential temperatures, and periodic waterbox cleaning typically prevents excessive fouling.
Several minor work orders had been written for the No. 11 steam generator feed pump (SGFP). However, the unit must be operating at a maximum of 50% when using only one of the two SGFPs. Since power was already reduced to 65 % for the elevated condenser differential temperatures, licensee management elected to further reduce power to 50% for the planned SGFP wor The inspector noted that the load reduction on January 14 was accomplished conservatively and in accordance with station procedures. In addition, the licensee's decision to further reduce unit load to accommodate the SGFP repairs was appropriat Unit 1 Manual Reactor Trip On January 16, 1993, Unit 1 control room operators initiated a manual reactor trip from 13% power following an automatic turbine trip and feedwater isolation. Operators were in the process of shutting down the unit from 50% power for control rod position indication system maintenance. During an attempt to place the steam dump (SD) system in service as per procedure, a number of SD valves inadvertently opened, creating a "swell" in all steam generator (SG) water levels. The high SG level automatic main turbine trip and feedwater isolation setpoints were reached, resulting in the respective actuations. In accordance with response procedures, the control room operators initiated a manual reactor trip. Operators manually shut the SD valves from the control room. Operators also implemented emergency
operating procedures. The overall plant response was normal. The licensee reported the reactor trip to the NRC in accordance with the reporting requirements of lOCFRSO. 7 Subsequent licensee investigation determined that electronic equipment failures within the SD system caused the valves to open. Troubleshooting activities duplicated the even The licensee originally initiated the shutdown in order to repair a previously identified flange leak on a 3/4 inch pipe in the reactor head vent system. That flanged joint is directly above the rod position and control rod coil stacks. The leak had caused operational problems with the analog rod position indication (ARPI) system associated with one control rod (204). The shutdown decision was based upon a potentially faulty ARPI connector and boron buildup on the ARPI coil stack. Upon shutdown, two coil stack connectors were subsequently replaced, and boron was removed from two coil stacks (directly below the flange leak). The licensee's inspection confirmed that no boron had leaked onto the reactor vessel hea The resident inspector responded to the site to evaluate licensee and plant response to the trip. The inspector concluded that the operator actions that initiated the manual reactor trip and implemented emergency operating procedures were timely and appropriate in response to the steam dump-induced transient. A manual steam line isolation was initiated to prevent excessive unit cooldown. In addition, the inspector monitored the licensee's trip followup activities and conducted an independent event review. The inspector monitored plant parameters, reviewed instrument traces and computerized event recorder printouts, and interviewed station personnel. The inspector verified overall plant response to the transient was as expected. The inspector noted that the licensee initiated a Significant Event Response Team (SERT) to independently evaluate the unit transient and manual trip, including equipment and personnel performanc The inspector observed the Station Operations Review Committee (SORC) meeting, conducted on January 19, to review the Post Reactor Trip Review Report (AD-16). The inspector concluded that the SORC had properly questioned and reviewed personnel, equipment and overall unit response for the January 16 event. In addition, the committee appropriately identified corrective actions required prior to unit startup. The inspector subsequently sampled selected corrective actions to verify completion. The inspector concluded that operator response to this event was very good. Integrated unit response was normal, and the SORC conducted an effective revie Unit 2 Manual Reactor Trip Reactor operators manually tripped the Unit 2 reactor at 1:52 p.m. on January 28, 199 The trip was initiated in response to a loss of both operating steam generator feedwater pumps (SGFPs) while operating at 100% power. Safety systems responded normally. A11 control rods inserted, and auxiliary feedwater started and recovered steam generator (SG)
levels. A manual steam line isolation was initiated to prevent excessive unit cooldow Operators entered abnormal and emergency operating procedures (AOP/EOPs) appropriately.
During recovery, one of two banks of backup pressurizer heaters was rendered inoperative when the non-safety related 460 volt supply breaker 2EPX failed. Workers in the area of the breaker cabinet heard a bang and observed a small amount of smoke. The Site Protection fire brigade responded. There was no fire in the area, and there was no actuation of the installed detection instrumentation and suppression systems. The licensee concluded that the fire detectors* in the area were functional and were within their surveillance testing interval, but were not subject to sufficient smoke to cause actuation. Reactor coolant system (RCS)
pressure decreased to about 2000 psig (normal operating pressure is 2235 psig) and then recovere A post-trip containment walkdown identified a tubing leak on the loop No. 22 RCS flow instrument line. Also, the No. 24 SG blowdown radiation monitor indication increased from 200 to 1000 counts per minute. The licensee identified radio-iodine in a SG sample and preliminarily concluded that a small primary-to-secondary leak existed. (See Section 3.2.1.C)
The licensee's investigation and followup activities determined that a technician was installing test equipment in the SG feedwater control cabinet at the time of the SGFP trips. They subsequently identified a loose connector in that cabinet, which caused an electrical transient, resulting in the SGFPs' increased speed demand and an ultimate trip on low suction pressur (See Section 4.3.1.B)
The unit remained in Mode 3 (Hot Standby), at normal operating pressure and temperature following the trip. The licensee completed troubleshooting, repair, and evaluation activities for the SG feedwater control system, the No. 22 reactor coolant system loop flow tubing leak, SGFP operational assessment, and No. 24 SG primary to secondary leak. The licensee formed a Significant Event Review Team (SERT) to independently evaluate the event. The licensee also performed their normal post trip review per procedure AD-16. The SERT and the station operations review committee (SORC) determined root cause to be equipment failure. SORC reviewed the completed AD-16 procedure on January 30, 1993, and authorized restart of the unit. The unit was subsequently restarted on January 31, 199 In addition, the licensee evaluated the coincident occurrence of vibration alarms on two reactor coolant pumps (23 shaft vibration and 22 motor flange vibration) and a metal impact monitoring system (MIMS) alarm on 21 SG.. These alarms occurred at 5:37 a.m. on January 28, 1993 (several hours before the trip). Westinghouse and PSE&G performed an evaluation and concluded these alarms were not related to either the 24 SG primary-to-secondary leak or the 22 RCS instrument line leak. Further, they concluded these alarms were probably due to an electrically induced signal, as two of the three systems have a common power supply and all three systems are located in proximity to each other in the control room. Westinghouse's judgement, based on the magnitude and duration of alarms and RCS loop transit times, was that the alarm indications were spurious. All these alarms immediately cleared, and the licensee continued to monitor the audible portion of the MIMS. Subsequently on February 2,
1993 (after restart), MIMS alarms occurred on the reactor vessel, however, they also quickly cleared. Westinghouse is continuing their review, including analysis of the MIMS tape recording The licensee's investigation of the 2EPX breaker fault determined that the failure was initiated in the breaker line side fingers (where the breaker fingers make contact with the motor control center bus stabs). The licensee determined that the breaker was a non-safety related component that provides backup containment penetration conductor overcurrent protection per UFSAR Table 8.3-4B. The licensee confirmed that the breaker was within its surveillance test and preventive maintenance intervals per Technical Specification 4.8. The breaker was last tested and maintained in January 1991 by performing an overcurrent test and a 5-year breaker overhaul. The licensee's root cause determination was continuing at the close of the inspection perio The inspector followed up on this event by reporting to the control room and observing post trip plant conditions and operator actions. The inspector noted good EOP implementation and SRO command and control. The inspector also followed up on root cause determination, SG primary-to-secondary leak analysis, RCS flow instrument line repair, the vibration and MIMS alarms, the breaker failure, SERT, SORC, and AD-16 activities. The inspector concluded that these activities were thorough and well performed. Inoperable Control Room Instrument Recorders During a control room panel review on January 19, 1992, the inspector identified that a number of Unit 1 instrument recorders were inoperable. Specifically, three of the four reactor coolant system (RCS) wide range temperature recorders and three of the four nuclear instrumentation power range (PR) recorders were "red-tagged," identifying them as being inoperable. Although the six recorders were properly tagged, the inspector found that only one RCS temperature recorder and one PR recorder was listed in the out of service instrument log (OD-13). None of these recorders were required to be operable by Technical Specifications. The inspector expressed a concern to licensee management that those recorders can provide useful trend and event analysis information and should receive a commensurate level of attention for repai The licensee subsequently added all six inoperable recorders to the OD-13 log for tracking purposes. In addition, the inspector noted that the three RCS temperature recorders were included on the January 29, 1993, Operations Priority List, providing increased attention for the repair of these recorders. At the end of the inspection period, only one RCS temperature and one PR recorder remained inoperabl The inspector concluded that the licensee initially did not provide appropriate attention to the repair of these recorders. However, the licensee's subsequent efforts were aggressive and effective.
2.2.2 Hope Creek Unit Operations The, Hope Creek unit remained at or near full power during the period. The inspectors monitored steady-state unit operations and performed routine inspection activities. The inspectors concluded that the licensee safely operated and maintained the unit during this inspection perio Open Item Followup (Closed) Unresolved Item (50-354/92-13-02). Primary Containment Venting: Incorporation of hardened plant vent and venting authorization into the emergency operating procedures (EOPs). The licensee revised the appropriate EOP (HC.OP-EO.ZZ-0318Q, Containment Venting, Revision 2, December 28, 1992). This revision described the operation of the hardened vent path from the torus, revised the venting approval authority and notification requirements, and made other minor corrections. The inspector reviewed the revised EOP, and discussed it with operators and managers. The inspector concluded that this revised EOP appropriately addressed the open item. The inspector had no further questions, and the unresolved item is closed. RADIOLOGICAL CONTROLS Inspection Activities PSE&G's conformance with the radiological protection program was verified on a periodic basi.2 Inspection Findings 3.2.1 Salem Unit 1 Containment Tour The inspectors toured the Unit 1 containmen.t on January 20, 1993, while the unit was shutdown in Mode 3 (Hot Standby). A radiation protection (RP) technician accompanied the inspectors, providing radiation work permit (RWP) coverage. The inspectors examined the pressurizer cubicle area, including a spray valve (lPSl) body-to-bonnet leak, the reactor vessel head area, including the vent flange leak repair, and other areas outside the biological shield.
The inspectors determined that the RWP was appropriate. The inspectors also noted very good radiological controls implemented by the RP technician. Overall, containment housekeeping and material condition was good. Specific deficiencies were directed to management personnel for corrective action Unit 1 Elevated Radiation Monitor lRllA Readin~
A Unit 1 containment ventilation isolation (CVI) occurred on January 25, 1993, when the containment particulate monitor (lRl lA) alarmed at its setpoint of 60,000 counts per minute (cpm). The licensee confirmed the CVI signal, made the required ENS call, notified the inspector, and sampled the containment atmosphere. This sample confirmed measurable rubidium-88 activity of approximately 2% of the 10CFR20 limit. The licensee determined that no radio-iodine was present in the sample. The licensee attributed this activity to power level changes during power ascension, to a small body-to-bonnet leak on spray valve lPSl and to a higher than normal fission product activity in the reactor coolant due to a minor fuel leak (See NRC Inspections 50-272/92-13 and 92-19). The lPSl leak and a leaking reactor vent system flange were repaired (See Section 4.3.1.A). The licensee also confirmed that the reactor coolant system unidentified leak rate was normal (approximately 0.2 gpm, which was less than the 1.0 gpm limit). Subsequent lRl lA readings decreased to 15,000 cpm, and additional containment samples did not detect any activit The licensee placed two of the five containment fan coil units in their filtered flow path alignment in an effort to -reduce the particulate activity and the associated 1R11 A reading Other containment radiation monitors indicated normal values. The licensee conducted a review of the lRl lA detector and electronics to ensure that the indications were valid. No abnormalities were identifie During this period the licensee submitted Licensee Event Report (LER) 92-26 which addresses two previous CVIs caused by elevated lRl lA readings. These events were reviewed in NRC Inspection 50-272/92-19. The licensee intends to supplement this LER with the recent CVI event and followup activitie The inspector confirmed licensee actions, monitored the lRl lA readings, reviewed the LER and incident reports, reviewed chemistry sample results, and discussed this item with appropriate licensee personnel. The inspector concluded that licensee followup actions were appropriate and will continue to monitor the effectiveness of those actions in identifying the cause(s) of and corrective actions for the elevated lRl lA reading Discovery and Analysis of Unit 2 Primary to Secondary Leak Following the Unit 2 manual reactor trip of January 28, 1993. control room operators noted an increase in the count rate indicated by the 2R19D radiation monitor. This radiation monitor provides indication of radioactivity present in the No. 24 steam generator blowdown line, and during normal plant operation usually reads approximately 200-400 counts per
minute (cpm), with an alarm setpoint of 2500 cpm. On January 28, the control room operators noted a reading as high as 1000 cpm, suspected that reading to be an indication of a primary to secondary leak, and requested that Salem Chemistry Department technicians sample the secondary side of the No. 24 steam generator. The normal at-power level of iodine-131 in the secondary side of a steam generator is below the minimum detectible level of lE-8 microcuries per milliliter (uCi/ml). The post-trip sample showed a level of approximately 5E-7 uCi/ml, and thus, confirmed the presence of a primary to secondary lea The Salem Chemistry Department conducted further sampling and analysis and determined the leak rate in the No. 24 steam generator to-be... approximately 1.0-1.5 gallons per day (gpd). This value is well below the Technical Specification limit of 500 gpd and the Salem administrative limit of 140 gpd. These limits ensure that the dosage contribution from the steam generator tube leakage will be limited to a small fraction of lOCFR Part 100 off-site dose limits in the event of either a steam generator tube rupture or steam line break. In view of the small estimated leak rate, the sensitivity (approximately 20 gpd) of the steam generator leak rate monitoring system, and the increased cognizance of operations personnel, Salem plant management concluded that Unit 2 could safely be returned to power operations and remain well within the plant's design basis. The licensee plans to inspect No. 24 steam generator at the unit's next refueling outage (scheduled to begin on March 20, 1993) and to take all necessary corrective actions to eliminate the leak flow path at that time.
The resident inspector staff monitored the initial actions taken by the control room operators and the sampling conducted by the chemistry technicians. The inspector subsequently discussed these actions with the Salem Chemistry Department Manager and reviewed the leak rate determination methodology used by the licensee to calculate the estimated leak rat Based on this effort, the inspector concluded that PSE&G acted conservatively and appropriately in determining that Salem Unit 2 could be safely operated at power and will monitor the licensee's efforts to repair the steam generator leak during the next refueling outag.2.2 Hope Creek Reactor Water Chemistry Update In late January 1993, the licensee resumed the injection of zinc into the feedwater stream in order to reduce radiation levels in the drywell and on the refuel floor when the unit was shutdown; and prepare for the implementation of hydrogen water chemistry in February 1993. The inspector reviewed the associated design change package for the startup of the hydrogen water chemistry program (DCP) 4HC-0242 and determined it to be adequate. The inspector also discussed numerous aspects of the startup plan with licensee supervision, and determined that the licensee took a conservative and deliberate approach to the implementation of the program. The licensee intends to inject sufficient hydrogen to mitigate
intergranular stress corrosion cracking (IGSCC) in the recirculation system piping and the reactor bottom head region. Other application will be considered as experience is accumulated. The inspector had no further question.
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 standard Portions of the following activities were observed by the inspector:
Work Order(WO) or Design Change Package CDCP)
Description Salem 1 Various Salem 1 Various Salem 2 WO 930125079 Hope Creek DCP 4HC-0242 Hope Creek WO 930118108 Spray valve IPSI leak repair Reactor head vent line flange leak repair Steam generator feedwater pump control system Hydrogen water chemistry
"B" reactor auxiliaries cooling system pump motor repair 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 technical 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, approved procedures, and NRC regulations.
The following surveillance tests were reviewed, with portions witnessed by the inspector:
Procedure N Salem I SP(0)4.4.6.2d Salem 2 S2. OP-ST.DG-0003(Q)
Hope Creek HC.OP-IS.EA-001 Reactor Coolant System - Water Inventory Balance Emergency Power System - No. 2C Emergency Diesel Generator
"A" Service Water Pump 92-day Inservice Test The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings 4.3.1 Salem Unit 1 Containment Leak Repair Activities The inspector reviewed licensee activities relative to a spray valve (lPSl) body-to-bonnet leak and a reactor head vent line flange leak. Both of these leaks were small (several drops per minute). The licensee calculated the combined leak rates to be less than 0.01 gp However, the containment airborne radiation levels had been noted to be increasing over the past few weeks (See NRC Inspection 50-272 and 311/92-19, and Section 3.2.1.B of this report).
The licensee elected to stop both of these leaks using leak repair and temporary modification (T-mod) procedures in accordance with the program requirements of Nuclear Administrative Procedure No. NC.NA-AP.ZZ-0013(Q). The licensee initiated T-mod Nos. 93-11 and 93-12. The licensee also performed lOCFRS0.59 safety evaluation reviews. These reviews concluded that no unreviewed safety questions were involved. The licensee repaired the lPSl valve by injecting the bonnet with sealant material, rendering the valve inoperativ The safety evaluation addressed issues concerning seismic, fire protection, transient analysis, valve bolt integrity, operation with one of two spray valves, environmental qualification, Technical Specifications and the FSAR. The licensee repaired the flange leak by building an encapsulation device and injecting it with sealant material. The reactor head vent line remained operabl The licensee completed repair activities and cleaned the affected areas of the boric acid deposits. In addition, two control rod position indicator connectors and cables were replaced, as boron deposits rendered the analog rod position indication (ARPI) inoperable for
control rod No. 204 (See also Section 2.2.1.A of this report). These leak repair activities were initially successful in stopping the leak The inspector reviewed the leak repair activities and contacted specialists in the NRC regional and headquarters offices. The inspector reviewed the associated documentation and inspected the repair activities in the containment. The inspector also viewed a video tape of the leaking equipment and boric acid deposits. The inspector confirmed that these repairs appeared to be effective in stopping the leaks and verified that the boric acid leaks were cleaned u The inspector noted that the reactor head vent system remained operable as required by Technical Specification (TS) 3.4.12. Further, the inspector noted that the lPSl spray valve was inoperable; however, the redundant valve (1 PS3) as well as the auxiliary spray system was operable. There are no TSs for the pressurizer spray valves. (The TS-required pressurizer code safety valves and power operated relief valves remained operable.) The inspector concluded that the activities observed were conducted in an appropriate manne Investigation and Root Cause for Unit 2 Manual Reactor Trip On January 28, 1993, reactor operators manually tripped the Unit 2 reactor (See Section 2.2.1.D) following the inadvertent loss of both operating steam generator feed pumps (SGFPs). At the time of the loss of the SGFPs, an instrument and control (I&C) technician was in the process of connecting test equipment to an electrical module in the steam generator (SG) control cabinet. This activity was performed in accordance with instructions provided in maintenance work order (WO) No. 930125079. The purpose of the activity was to monitor selected parameters in response to indicated feedwater flow spikes experienced on January 25, 199 The licensee investigated the event and determined the root cause of the loss of the SGFP During the investigation, the licensee identified that the common test jack on the SGFP master controller was loose, providing a ground path for the controller. In an attempt to repeat the event, test pins were inserted and allowed to contact the metal faceplate (as would have been allowed with the loose connector); both SGFP demand signals quickly went to maximum. It was also postulated that the loose test jack was the cause for the initial feed flow spikes observed on January 25. Nonetheless; selected points will continue to be monitored for verification purpose The test jack connectors are part of permanent plant equipment. In response to this event, the licensee verified the integrity of other related, similar connectors. No other loose connectors were identified. In addition, the licensee plans to verify the integrity of similar connectors on other equipment as those components are tested as part of the normal surveillance program. The licensee attributed the root cause of this event to be equipment failure.
The inspector reviewed the licensee's WO and troubleshooting plans, interviewed instrumentation and control technicians and supervisors, an,d monitored the associated investigative activities. The inspector concluded that the activities were well conducted and thorough, done in accordance with prescribed procedures, and agreed that the root cause was due to installed equipment problem.3.2 Hope Creek Reactor Core Isolation Cooling (RCIC) System Discharge Valve Failure On January 19, 1993, during the performance of surveillance test HC.IC-FT.BB-034,
"Nuclear Boiler Division 4 channel B21-N697D Reactor Vessel Level," the RCIC pump discharge valve BD-HV-F012 unexpectedly closed, and its motor breaker tripped ope Operators declared RCIC inoperable and entered the appropriate Technical Specification (TS)
action statement. The action statement was exited and RCIC declared operable approximately one-half hour later when the F012 valve was manually reopened to its normal positio The licensee's investigation determined that the F012 valve stroked closed because of the test switch alignment in the logic circuitry tester being used in the surveillance test. Upon closing, the "full closed" limit switch failed to open, resulting in the valve disc being driven into its seat. The motor breaker tripped open on overload, however, actuator damage had already occurred. The logic tester used the closed limit switch to indicate valve position, not the closing torque switch, which was effectively removed from the closing protection circuitry. Maintenance personnel replaced the actuator motor and adjusted the limit switches, returning the valve to full service on January 22, 1993. The licensee's investigation into the cause of the incident was ongoing when the inspection period ende The inspector noted that the licensee's activities surrounding this event were comprehensive and appropriate. While the safety significance of this event was minimal, the licensee demonstrated a clear appreciation of the event's impact on RCIC operation and the need to return the valve to a fully operable status in a timely manne Open Item Followup (Closed) Unresolved Item (50-354/91-04-01) Manual Valve Position Verification and Operation. In February 1991, a series of instrument rack isolation valve manipulations led to a number of primary containment isolation system actuations during maintenance, testing and modification. Also, confusion existed on how technicians were to verify valve position during a valve lineup check or verification. The inspector reviewed procedure IC-GP.ZZ-020, "Instrument Valve Lineup Verification," which provided guidance to personnel performing valve lineup checks. The procedure provided clear. instructions in verifying valves in both the open and closed positions. These instructions were in accordance with generally accepted industry practice. Additionally, the inspector verified that personnel
performing valve lineup checks received hands-on experience using a mock instrument rac The inspector noted that there had been no plant transients or system actuations caused by manual valve manipulation during lineup checks since the February 1991 events. Also, the installation of calibration volume chambers in accordance with design change package 4HC-205 to reduce instrument sensitivity during surveillances was completed during the fourth refueling outage in the fall of 1992. Based on the foregoing, the inspector concluded that the licensee had appropriately addressed the issues surrounding valve lineups checks and valve manipulations on sensitive instrument racks. This unresolved item is close.
EMERGENCY PREPAREDNESS Inspection Activity The inspector reviewed PSE&G's conformance with 10CFR50.47 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 Open Item Followup (Closed) Unresolved Items (50-272 and 311/92-13-01 and 354/92-13-04). Implementation of 10CFR50.54x; deviations from NRC requirements in order to protect the public health and safety. Relative to this issue, the licensee reviewed their procedures, conducted training, and successfully performed the annual emergency exercise. During that exercise, the licensee demonstrated adequate implementation of 10CFR50.54x requirements. (See NRC Inspections 50-272, 311 and 354/92-14; and 50-272, 311 and 354/92-17 and 92-18.) Based on this, these items are close.
SECURITY Inspection Activity
. PSE&G's conformance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundarie.2 Inspection Findings There were no noteworthy findings.
- ENGINEERING/TECHNICAL SUPPORT Salem Unit 1 Technical Specification (TS) 3.0.3 Entries Due to Failed Boric Acid Storage Tank Level Indication During this inspection period, the licensee entered *Ts 3.0.3 on two occasions after the level indicator for a Unit 1 boric acid storage tank (BAST) became inoperable. On each occasion, the unit was operating in Mode 1 (Power Operation). The No. 12 BAST tank was inoperable due to tank level and low boron concerl"tration concerns, while the No. 11 BAST remained operable. However, on January 23, 1993, at 12:30 p.m., and on January 27, at 2: 10 p.m., the No. 11 BAST level indication failed. Per the Action requirements of TS 3.3.3.7, one BAST level indication is permitted to be inoperable provided the remaining BAST can satisfy the level, boron concentration and temperature requirements of TS 3.1.2.8.a. Since TS 3.1.2.8.a could not be satisfied due to No. 12 BAST being inoperable, TS 3.0.3 was entere In response to the failed BAST level indication, the licensee performed a blowdown of the associated bubbler in the level indication system. For each instance, the level indication was restored (and TS 3.0.3 exited) within about 30 minutes, thereby avoiding a unit shutdow These occurrences have been recurring at both Salem units (See Unit 1 Licensee Event Report 92-23). Periodic blowdown frequency has been increased as an interim corrective action. System Engineering is continuing an assessment of the repetitive failures to determine longer term effective corrective action The inspector reviewed the licensee's response and TS implementation and concluded that the immediate actions taken were appropriate. However, increased attention in this area is warranted as TS 3.0.3 entries represent a challenge to the organization in responding to these event Unit 1 Startup and &timated Critical Position (ECP)
The licensee restarted Unit 1 on January 21, 1993, after a manual -reactor trip that occurred on January 1, 1993 (See Section 2.2.1.C). Reactor engineering personnel calculated an ECP per procedure Sl.RE-RA.ZZ-OOOl(Q). Criticality was predicted for 130 steps on control rod bank D. Licensee procedures require a calculation for a criticality tolerance window of +
500 percent milli-rho (pcm). That is, criticality should occur within this tolerance window (control rod bank D between 70 and 225 steps for this startup). Technical Specification (TS) 4.1.1.1.2 requires the core reactivity balance to be within + 1 % delta K per K (which is equivalent to + 1000 pcm) of predicted criticality. In addition, TS 3.1.3.5 addresses control rod insertion limits (RIL) such that control bank C has to be greater than 58 steps (with bank D at zero) when criticality is achieved.
During the startup on January 21, 1993, criticality was achieved at 10:29 p.m. with control rod bank D at 67 steps. Since this was not within the + 500 pcm tolerance ~indow, reactor operators inserted all control rods in order to shut down the Unit 1 reactor. This action was required by integrated operating procedure IOP-The licensee determined that an error was made in the ECP. The previous critical condition for the reactor was taken at 50% power on January 15, 1993, at 8:46 a.m. An apparent boron concentration error occurred due to a sample time difference because the unit was borating to accommodate a xenon transient. This boron concentration error thus caused an error in the predicted ECP for the January 21, 1993, startu After the unit was shutdown, the licensee recalculated the ECP. The licensee restarted the reactor, and criticality was achieved at 6:28 a.m. on January 22, 1993, without any problems. The licensee had preliminarily concluded that the error in the initial ECP was due to a procedure inadequacy and a personnel error. The incident report (92-058) investigation was ongoing at the close of the inspection perio The inspector reviewed the incident report, both ECPs, reactor engineering and operations procedures and TSs. The inspector discussed this event with licensee operations and reactor engineering personnel. The inspector concluded that there were no TS issues and that the licensee acted appropriately when criticality was achieved earlier than predicted. This item is unresolved pending the completion of the licensee incident report and NRC review (URI 50-272/93-01-01). Emergency Diesel Generator Overspeed During Troubleshooting On January 25, 1993, the Unit 2 No. 2C emergency diesel generator (EDG) automatica1ly tripped (shutdown) on overspeed while the EDG was running unloaded to support troubleshooting activities. The licensee was running the EDG to investigate increased stator voltage times noted during the performance of recent surveillance test A troubleshooting work plan was developed for the electrical troubleshooting in accordance with procedure No. SC.IC-GP.ZZ-0006(Q) as supplemented by detailed instructions that were developed by the electrical system engineer. The body of the instructions provide for connecting electrical test equipment for monitoring several parameters. Step 5.14 of the detailed instructions state "DISCONNECT recorder test leads and any other test equipment,"
a s_tep that is preceded by instructions to stop the EDG (Step 5. 11).
During the troubleshooting activities, and with the EDG running unloaded at rated speed (900 RPM), the technician began removing the test equipment. The licensee's investigation postulated that when an associated cabinet door was opened, a test jack lead inadvertently touched an adjacent terminal. It was verified by reviewing plant drawings that such a
bridged connection would initiate air start motor rotation and energize the fuel rack* booster solenoid valve to engage the fuel rack toward its maximum position. Personnel in the
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vicinity of the EDG at the time of the overspeed confirmed rotation of one or more air start motors. The licensee concluded that the action of the fuel rack is the most likely cause for the EDG overspeed condition. The licensee did not believe that the air start motors engaged the flywheel when the EDG was operating at 900 RPM. In addition, a 100% visual inspection of the flywheel and all four air start motor pinions and shafts was conducted; no significant wear was identified. The licensee's EDG investigation and followup testing continued for about one full day. There were no indications of adverse effects on the 2C ED The inspector independently reviewed this event and identified the following concerns. First, the work instructions were not followed in sequence. Second, the mechanical system engineer was also conducting troubleshooting activities simultaneously with monitoring equipment connected to the 2C EDG. However, those activities were not doc~mented and controlled per the required SC.IC-GP.ZZ-0006(Q) process. Third, it appeared that if the same electrical bridge were allowed to occur even after the EDG were shutdown, an inadvertent EDG start could have resulted. This implies that the risks of the above activities were not adequately realized or evaluated. Finally, the EDG was started three times, and it was not evident that the associated troubleshooting procedure SC.IC-GP.ZZ-0006{Q) was completed and documented for each related test ru The inspector concluded that, based on the above findings, the integrated troubleshooting activities were not thoroughly evaluated, controlled and documented. At the close of the period, the licensee was finalizing their review and followup activities, including completion of the incident report. In addition, the independent safety review group is performing a review and assessment of this event. Pending completion of these activities and subsequent NRC review for potential enforcement actions, this item is unresolved (URI 50-311/93-01-02). Open Item Followup (Closed) Unresolved Items (50-272 and 311/92-01-06; 91-28-02). Auxiliary feedwater flow outside the design basis. NRC Inspection 50-272 and 311/92-04 reviewed this item in detail, and the NRC exercised discretion in a letter dated June 17, 1992. Licensee Event Report (LER) 91-36 also addressed this issue. The item was left open pending licensee submittal of a licensing change request addressing shutdown margin, containment pressure setpoint and time response. PSE&G submitted a license change request (LCR 92-04) dated May 26, 1992, addressing these issues. Based on this, the two unresolved items are close (Closed) Unresolved Item (50-272/92-04-02). Main steam line radiation monitors (R46)
incorrect detector installation. Several of the Unit 1 and Unit 2 R46 detectors had an improper range (1.0 mr/hr to 100 R/hr in lieu of the correct range of 0.1 mr/hr to 10 R/hr).
The licensee committed to submitting a revised LER 92-04, addressing root cause and
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corrective actions. This was accomplished with Supplement 1 to LER 92-04, dated July 23, 1992. The LER was reviewed and closed in NRC Inspection 50-272/92-12. Based on this, the unresolved item is close.2 Hope Creek Open Item Followup (Closed) Unresolved Item (50-354/92-18-03). Emergency Diesel Generator (EDG) Fuel Oil Pump Failure. Following an overhaul and test run of the "B" EDG in November 1992, the licensee determined that the engine driven fuel oil pump did not operate as designed. The licensee's investigation revealed that the pump's internals were incorrectly configured for Hope Creek's counter-clockwise rotating EDGs. In accordance with their procedures the licensee evaluated this condition for reportability under 10CFR21. The licensee determined that the reduced fuel oil flow would not provide sufficient cooling and lubrication, which could have led to catastrophic failure if the unit was running for a significant period of time, creating a substantial safety hazard. Based on this conclusion, the licensee made a 10CFR2 l notification to the NRC on January 11, 1993. Of the three fuel oil pumps owned by the licensee, the one installed on the "B" EDG and one of two spares were reconfigured to meet design; the second spare was returned to the vendor (Colt Industries) for rewor The inspector reviewed the licensee's activities dealing with this issue and concluded that the evaluation appeared well-reasoned and technically sound and that the corrective actions were appropriate. The licensee also requested the vendor perform a complete evaluation of this issue on January 6, 1993. The inspector concluded that the licensee had acceptably resolved this issue, therefore the unresolved item and the Part 21 report are close (Open) Unresolved Item (50-354/92-80-15). This item involved the lack of data trending or analysis of the 1AX501 and 1BX501 transformers' oil identified during the February 1992 Electrical Distribution System Functional Inspection (EDSFI). These transformers feed the normal and alternate power to the safety-related busses and are considered important to safety. At the time of the EDSFI, the licensee stated that they did trend oil analysis data, but the data was not immediately retrievable since the system engineer for the transformers had retired. In response to the question whether the data had been reviewed against industry codes and standards, such as ANSI C57.104, 1978, the licensee stated that they had not done a rigorous analysis of the data. However, they stated that if the data appeared to be unusual the system engineer would complete a rough calculation to check it. These calculations were also not availabl On December 4, 1992, the inspector reviewed the status of the updated Hope Creek transformer oil analysis program. The licensee presented to the NRC various transformer oil analysis data and explained how the Distribution System Department and outside consultants were used to evaluate the oil data, when necessary. The inspector reviewed the data relative
to various industry criteria, including the "Rogers Ratios" criteria. The review to the.
"Rogers Ratios" criteria was performed by the corporate engineering group, but it was not routinely requested by the system enginee From the presentation, the inspector concluded that, based on the various inputs, there was no problem with transformers 1AX501 and 1BX501. However, one analysis indicated some heating and degradation of the units. The inspector noted that the transformer operated at 25 to 30 percent of the nameplate rating. Further discussions with the licensee determined that:
(1) the information was not available during the EDSFI, when the issue was raised; (2) the licensee expected a heating increase if the units were run at their full nameplate rating, but no data was available to predict what temperature would be reached; (3) the licensee was not aware of any other transformers of the type used at Hope Creek showing overheating and insulation degradation; and (4) no special maintenance, test or inspection on the units had been planned beyond the current activitie The inspector interviewed licensee personnel and reviewed the raw transformer oil data as presented by the licensee. None of the data included the transformer loading level when the gas sample was taken or analyses beyond the simple trending of the basic gas data. The slight overheating discovered during the EDSFI was not documented, nor was the consultant's similar observation and recommendation to not increase sample frequency. The inspector also found that the data had been compiled and trended since the EDSFI.
The inspector's review of the oil data concluded that continued trending of oil data was necessary to verify the integrity of the transformers. This item remains open pending completion of NRC review of PSE&G's documentation of transformer analyses and evaluatio.
SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Pre-Outage Meeting On January 12, 1993, the inspector attended a periodic pre-outage meeting for the upcoming Unit 1 and 2 refueling outages currently scheduled to began on October 2, 1993, and March 20, 1993, respectively. Critical path items, progress on work preparations and current open items were discussed. The outage manager also discussed plans to conduct training related to critical path, the work flow process and schedule reading, to provide for enhanced outage conduct and control. The inspector concluded that the outage planning for both units'
outages was progressing well.
19 Station Operations Review Committee (SORC)
The inspector attended the post reactor trip activities of SORC (sections 2.2.1.C and D).
The inspector noted that SORC displayed a good questioning attitude and safety perspectiv Their review of the trip root causes and corrective actions was thoroug New Shift Schedule for Salem Operations Shift Supervision During the back-to-back refueling outages conducted at Salem Units 1 and 2 in 1992, Salem Operations management placed shift senior reactor operators (SROs) on a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift schedule and maintained the reactor operators (ROs) and equipment operators (EOs) on their usual 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts. Salem Operations management initiated this shift schedule change in order to have more shift supervision available to better support the increased outage workload. When the*refueling outages ended in August 1992, the SROs returned to their original 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift rotation, yet both the *SROs and Salem Operations management had found the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> rotation advantageous from a performance and morale standpoint. Salem Operations management subsequently attempted to schedule both the shift SROs and the shift RO/EOs on a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> rotation, but the ROs/EOs' union protested, and the new shift rotation was prevented from being implemented. Due to the perceived advantages of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift, however, Salem management pursued a split shift rotation where the SR Os would work 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts while the RO/EOs maintained the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> schedule. The Salem Operations Manager requested and received permission from PSE&G senior management to institute the split shift rotation, and the new shift schedule was implemented on November 15, 199 The NRC resident staff had noted the advantages gained by having the extra shift supervision provided by the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift schedule during the Salem refueling outages, yet had concerns with the permanent split being implemented in the SRO and RO shift rotations. The SROs and ROs of the former shift crews would not be remaining on the same schedule, and shift teams' unity would be lost. The inspectors discussed the matter with the Salem Operations Manager and reviewed the presentation the Salem Operations Manager had presented to PSE&G senior management. In addition, the inspectors closely monitored both individual operator and shift crew team performance in the two months that followed the split shift rotation-implementation. The inspectors concluded that licensed operator individual and team performance had not suffered and that Salem management had safely instituted the new SRO shift rotation in order to take advantage of the improved morale and performance. The inspectors also noted that periodic requalification simulator training is conducted with the original shift team.2 Hope Creek Open Item Followup (Closed) Unresolved Item (50-354/92-13-05). As a result of an apparently higher than expected personnel error rate during the fourth refueling outage, the licensee undertook an
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independent assessment of incidents occurring during the outage to determine whether any
- common cause or causes existed and to provide recommendations for performance improvement. The results of this effort were transmitted to the NRC on January 29, 199 The licensee determined that although there were* five groups of similar causal factors, no
"common thread" could be discerned. Additionally, the licensee compared the incident report issue rate of the third refueling outage to the fourth and determined that there was no discemable difference, despite a lower reporting threshold used during the fourth refueling outage. The licensee indicated that lessons learned from the fourth refueling outage, as summarized in the departmental post-outage critiques, would be applied to future outage The inspector concluded that the licensee's assesstnent of the personnel error events was comprehensive and rigorous and fully supported their conclusions. The effectiveness of the recommendations will be assessed during upcoming outages. This unresolved item is therefore close.3 Common Open Item Followup (Closed) Unresolved Item (50-272 and 311/91-16-03). Nuclear Services Department administrative and management controls for contractor personnel. The licensee addressed the concerns in a new procedure TSH.NS-AP.ZZ-0068(Q), "Control of Contractor Work," dated September 30, 1991. This procedure defined the qualification requirements and the control of field activities. Subsequently, a nuclear department administrative procedure, NC.NA-AP.ZZ-0068(Q), "Control of On-Site Contractor Personnel," was issued on June 1, 199 This procedure addresses all phases of contractor control, including mobilizing and controlling contractors who work for the nuclear departmen The inspector reviewed these administrative procedures and concluded that they appropriately address the issue associated with the open item. Based on this, the unresolved item is close (Closed) Unresolved Item (50-272, 311 and 354/92-05-01). Cross training of workers at Salem and Hope Creek. Salem and Hope Creek share personnel at times, especially during refueling outages. This includes maintenance, engineering, and radiation protection/chemistry personnel. A weakness was identified in that a formal cross training program addressing station differences did not exist. The licensee revised specific training programs and procedures to ensure that a cross training of Salem/Hope Creek personnel, as well as for personnel from other places, occurs. The inspector reviewed selected procedures and discussed this item with licensee personnel. Based on this review, the unresolved item is closed.
- LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports PSE&G submitted the following licensee event reports, and special and periodic reports, which were reviewed for accuracy and evaluation adequacy:
Salem and Hope Creek Monthly Operating Reports for December 199 *
Salem Unit 1 Special Report 92-8 was submitted to address fire barrier penetration seals that were impaired for greater than seven days, a report required by Technical Specification 3. 7.1 *
Salem Unit 1 Special Report 93-1, dated January 28, 1993, discussed the inoperability of radiation monitors 1R45B and 1R45C, plant vent medium and high range noble gas monitors, for greater than seven day *
Salem Unit 2 Special Report 92-7 concerned the inoperability of a fire door for greater than seven days, submitted pursuant to Technical Specification 3. 7.11.a.
Hope Creek Annual Report - Technical Specification 6.9.1.5. During 1992, there were no unplanned challenges to the main steam line safety/relief valves. Also, all the valves were tested in November 1992 during the fourth refueling outag No significant observations were mad Salem LERs Unit I None Unit 2
LER 92-26 concerned a containment isolation due to the IRI IA, containment particulate airborne monitor (See Section 3.2.1.B).
Hope Creek
LER 90-07-01 supplemented information provided in LER 90-07 concerning corrective actions taken to improve the reliability of reactor protection system electrical protection assemblies (EPA). New logic cards had been installed in the alternate power supply EPA as recommended by General Electric Company service
information letter (SIL) 496. However, this introduced a new problem associated with the trip logic which could not be reset without tripping the EPA. The licensee decided not to install the new cards in either normal power supply EPA until this problem is resolved. The inspector reviewed this revision to LER 90-07, noted the licensee's actions and concluded that the licensee's decision to delay full implementation of the EPA cards was conservative and appropriat *
LER 90-33-01 dealt with the same issue as LER 90-07-01 above. Information presented was similar in content as wel The LERs reviewed were found to be acceptabl.2 Open Items The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose &311/92-13-01 50-272&311/91-28-02 50-272&311192-01-06 50-272&311/92-04-02 50-272&311/91-16-03 50-272&311/92-05-01 Hope Creek 50-354/92-13-02 50-354/91-04-01 50-354/92-13-04 50-354/92-80-15 50-354/92-18-03 50-354/92-13-05 50-354/92-05-01 Report Section 5.......2..3...... Closed Closed Closed Closed Closed Closed Closed Closed Closed Open Closed Closed Closed
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1 EXIT INTERVIEWS/MEETINGS 1 Resident Exit Meeting The inspectors met with Mr. V. Polizzi and Mr. R. Hovey and other PSE&G personnel periodically and at the end of the inspection 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 information subject to 10 CFR 2 restriction.2 Specialist Entrance and Exit Meetings Date(s)
1/11-15/93 1/4-8/92; 1/19-22/93 2/1-5/93 Subject Environmental Monitoring Inspection Report N Reporting Inspector 50-272, 311 and 354/93-04 Peluso Chemistry/Inservice 50-272, 311 and 354/93-03 Kaplan/Chaudhary Inspection/Pipe Supports Security 50-272, 311 and 354/93-05 Albert 1 Management Meetings The inspectors attended a meeting on January 21, 1993, between Region I Division of Reactor Safety (Operation Licensing Branch) and PSE&G Training Department management personnel. Current training and operator licensing issues were discussed.